52 Mud Logging

Chapter 52 Mud Logging Alun H. Whittaker, Exploration Logging IX.*

Introduction Conventional mud logging has been commercially available since 1939. The service involves extraction of gases from the returning mud stream and analysis of the gas for combustible hydrocarbons. Commonly, the resulting analyses are logged at drilled depth and plotted alongside a drill-time or rate of penetration log and a cuttings sample geological log. Although the mud log data cannot be related directly to undisturbed reservoir properties, they are important indicators of potentially productive horizons in the well. The conventional mud log continues to be the most important geological data source available before wireline logs are run.

The mud logging unit offers a useful location for the operation of other wellsite analyses and services. It provides a clean, well-lighted laboratory area with a stable electrical supply and is continuously operated by geologists or geologically trained technicians. Many mud logging contractors have made use of these assets to augment conventional mud logging with an extensive range of geological and engineering services. Often unrelated to the traditional gas analysis function of the unit, these services nevertheless generally are considered aspects of mud logging now in the same manner as sonic, density, and neutron logs often are grouped with “electric logs.”

The earliest expansion of mud logging services began in the 1960’s with the introduction of improved methods of geopressure detection. New techniques were added to the logging unit and it became common for a separate “pressure log” to be prepared alongside the mud log. The 24-hour activity of the mud logging unit allowed continuous operation of this service in which early detection was essential.

In the 1970’s, the advent of rugged microelectronics allowed the introduction of more sophisticated and automated equipment into the logging unit. Most notably, the use of drilling rig data-acquisition systems

‘The chapter on this topic In the 1962 edibon was written by A.J. Pearson.

linked to minicomputers introduced a range of drilling optimization and control services. Unlike conventional mud logging and geopressure detection, these services are essentially nongeological. Generally, engineering personnel are added to the logging crew for these services.

In the 1980’s three new aspects to mud logging services have been introduced. First, direct links between a wellsite minicomputer and an office data center allow centralized surveillance and control of several wells. The logging unit provides a wellsite access point to the central computer data base and analytical software.

Second, there is the increasing use of the mud logging unit as the surface receiving and control center for downhole measurement-while-drilling (MWD) services. The mud logging unit provides both a convenient working environment and support data (e.g., total depth measurement) for this service. Additionally, the ability to integrate mud logging and MWD data in a single computer adds economy and speed to the well evaluation process.

Third, the 1980’s have brought the first fundamental changes in the methods of hydrocation and geological analysis, which continue to be the common denominator of all mud logging services. Improved sampling techniques, pyrolysis, chromatography, and other geochemical techniques have enhanced the diagnostic and quantitative value of mud logging. Wellsire geochemical screening for reservoir and source-bed type may now be performed in the mud logging unit.

Service Types The number and range of mud logging contractors is possibly greater than that of any other oilfield service. The logging services offered by any single contractor may range from basic hydrocarbon logging, using equipment barely more sophisticated than that introduced 40 years ago, to complex chemical and physical analyses and a complete engineering surveillance and control center.

52-2 PETROLEUM ENGINEERING HANDBOOK

Similarly, logging personnel may be graduate geologists or engineers, or technicians of various levels of expertise. In specifying the mud log service for a well, the operator’s engineer, geologist, and the logging contractor should define the objectives and problems an- ticipated and select those aspects of the service required.

Since extra service usually implies extra cost, economics must play a part in the decision. In engineering monitoring, it is relatively easy to compute the saving in drilling time or cost required to justify some addition to logging service day rate. This is discussed in detail at the end of this chapter.

Although overlaps occur, the services provided in mud logging may be grouped in line with the traditional oilfield disciplines: (1) formation evaluation services ’ -hydrocarbon analysis, geological analysis, and geochemical analysis; (2) petroleum engineering services-geopressure evaluation and petrophysical measurements; (3) drilling en@neering services-data acquisition and data analysis. This order is convenient for the following discussion of logging services since it closely parallels the historical development of mud logging and the level of sophistication of logging units used today.

Formation Evaluation Services Gas Extraction Methods Although the modem mud logging unit may perform many different services, probably its most critical one is the analysis of hydrocarbon gases. 2 Before this analysis can be performed, a sample of gas must be extracted from the drilling mud. This is performed by the gas trap (Fig. 52.1).

The gas trap is a square or cylindrical metal box immersed in the shale shaker ditch, preferably in a location

Fig. Cl-Gas extra

of maximum mud flow rate. Ports in the lower part of the trap allow mud to enter and leave the trap. An electric or pneumatic agitator motor provides both pumping and degassing of mud passing through the trap.

Gas evolved from the mud is mixed with ambient air in the upper part of the trap and drawn through a vacuum line to the logging unit for analysis. This device provides a relatively cheap and reliable method of obtaining a continuous gas sample. However, the efficiency of the device is somewhat affected by drilling practice. Pump rate and ditch mud level will influence mud flow rate through the trap; mud rheology will be a factor in the degassing efficiency of the trap; and mud and ambient air temperature around the trap and vacuum line will affect the relative efficiency with which light and heavy hydrocarbons are extracted and retained in the gas phase. This latter effect is most noticeable in areas of high diurnal temperature variation, where heavier alkane gases seen in daylight may condense and be lost in the cold of night.

An alternative to the conventional gas trap is the steam, or vacuum, mud still. In this device, a small sample of drilling mud is collected at the ditch, returned to the logging unit, and distilled under vacuum. The method provides a relatively high and uniform extraction efficiency for all hydrocarbons. It is, however, a time- consuming manual process. Analyses are noncontinuous and subject to human error; for example, light hydrocarbons can evaporate while the sample stands prior to analysis.

While a useful addition to the conventional gas trap at times, the mud still does not provide a real alternative. The development of a continuous gas trap with good and consistent efficiency of extraction is a high priority in the improvement of mud logging technology.

ction at the ditch

MUD LOGGING 52-3

Hydrocarbon Analysis The basic form of gas analysis involves the analysis by combustion of the bulk sample. Although commonly called “total gas analysis,” it is, in reality, analysis for total combustible gases and primarily detects the low- molecular-weight alkanes (paraffins) such as methane, ethane, propane, butane, and pentane (with partial concentrations of hexane and heptane at higher ambient temperatures).

Catalytic Combustion Detector (CCD). After filtration and drying, the gas stream is injected at constant pressure and flowrate into a detector chamber (Fig. 52.2). The original type of mud logging gas detector, and probably still the most widely used, is the catalytic combustion, or “hot wire” detector (Fig. 52.3).

The hot wire detector is a Wheatstone bridge circuit consisting of four resistances: a fixed resistor, Rf; a rheostat, R,, used to trim or balance the bridge; and a matched pair of coiled platinum wire filaments, Rd and R,. The two filaments are enclosed in an analysis cell with the detector filament, Rd, exposed to the flow of gas sample and the reference filament, R,, isolated in pure air.

When a bridge voltage, V, is applied, the filaments become heated. A voltage between two and three volts is commonly selected to give a high enough filament temperature for hydrocarbon combustion at the filament surface (actual voltage used depends on the particular detector design). Combustion heat causes the temperature and hence resistance of the detector filament to rise relative to the reference filament. The bridge is unbalanced and current flows between the two sides of the bridge. Using a galvanometer of resistance R, , this current, I,, can be measured. Since combustion occurs at the filament surface only, the galvanometer current is quite sensitive and linear with changing gas concentration.

Obviously, detector response will depend on both the concentration and composition of the sample gas phase, since each hydrocarbon species will have its own particular heat of combustion. Table 52.1 shows these for the low-molecular-weight alkanes.

Since gas composition is unknown, the total gas detector cannot be calibrated for tme compositional response. The detector is calibrated with a mixture of a single alkane, usually methane, in air. Detector response is then reported in percentage “equivalent methane in air” or EMA. Using a variable resistance, R,, in the bridge it is possible to adjust the bridge current, I,, and graduate the galvanometer directly in percentage EMA. An older practice, which is now becoming obsolete, was to take the galvanometer reading in milliamps and relabel it as “gas units.” Such units are obviously equipment specific although some company or regional standards have been enforced. Where this practice continues, confusion can be avoided by requiring the logging contractor to report calibration data on the mud log heading. For example, the contractor would report “ 100 total gas units=2% EMA.”

Fig. 52.4 shows the response of a typical CCD to commonly occurring combustible gases. Notice that a response of 1% EMA, or 50 total gas units, may indicate a concentration of 1% methane or a somewhat lower

:VACuUM PUMP r PRESSURE 1 REGULATOR

Fig. 52.2-Gas analysis system.

ZERO ADJUST POTENTIOMETER

L SPAN ADJUST POTENTIOMETER

Fig. 52.3-Catalytic combustion detector.

TABLE 52.1-HEATS OF COMBUSTION OF THE SIMPLE ALKANES

Cn +2n+2)

(3n + 1) +-O,-nCO,+(n+l) H,O+E

2

Molecular E n=1 Weight (kcallmol) kcallgm Structure

Methane 1 16 191 11.9 i

Ethane 2 30 342 11.4 u”

Propane 3 44 493 11.2 tit

Iso-butane 4 56 648 11.2 A

Butane 4 58 650 11.2 j-c+4


ZERO 0 0.2 0.4 0.6 0.8 1.0 x2 I.4 16 , 8 20

AO.JvsT PERCENT ““DROt.aRBON IN AIR

Fig. 52.4-Catalytic combustion detector response.

concentration of a mixture of methane and heavier alkanes. Total gas response may be thought of as a “gas richness indicator,” increasing both with gas concentration and with addition of heavier fractions.

To assist in discriminating light alkanes from heavy ones, a second identical detector may be used. By setting a lower bridge voltage (1 to 1.4 V) and filament temperature, the detector is no longer capable of induc- ing combustion of methane. The resulting detector output, still reported in percentage EMA, is commonly labeled petroleum vapors, wet gas, or heavies, although only qualitative comparison of the two detector responses allows recognition of dry and oil-associated gas shows.

Response of the CCD can be maintained linearly up to the stoichiometric, or ideal, combustion composition of hydrocarbon in air. Above this composition, approximately 9.5% EMA, the detector “saturates,” in- complete combustion occurs, and response becomes nonlinear. At higher concentrations, the sample must be diluted with air before it is introduced into the sample chamber to maintain a combustible gas mixture.

Theoretically, by using progressive sample dilution, a CCD can be maintained linearly up to concentrations of 100% EMA. In reality, each dilution stage requires a reduction in gas sample volume and an increasing mixing error. It is generally accepted that 40% EMA is the maximum limit of reliability of a CCD.

As an alternative to progressive dilution, where high gas concentrations are regularly expected, the detector can be reconfigured to operate as a thermal conductivity detector (TCD). Though the detector circuit remains essentially unchanged, it is operated at a lower voltage such that no gas combustion occurs. Bridge current now is reversed, responding to the cooling effect of the gas stream passing over the detector filament. Methane, which has a substantially greater thermal conductivity than air, will produce a large cooling effect, which may be linearly calibrated up to very high concentrations. The device is, however, poorly responsive to the heavier alkanes, CO2 and hydrogen sulfide (HzS), which have thermal conductivities close to that of air. The high conductivity gases, hydrogen and helium, will give responses even greater than that of methane.

The CCD is quite selective for hydrocarbons. Carbon dioxide (COZ) and hydrogen sulfide (HzS) will not bum at the detector filament. They will marginally reduce the

HYDROGEN

+1 7+ *In SAMPLE +-J

Fig. 52.5-Flame ionization detector.

+ Ii20

thermal conductivity of the gas mixture and induce a small heating effect at the detector filament. This positive response is commonly so small as to be in- significant when compared with the greater hydrocarbon response. However, if the concentration of noncombusti- ble gases becomes so high as to prevent complete combustion of hydrocarbon with air, a much larger negative response will occur.

Hydrogen will bum in the detector, even at low voltage, giving a concentration response similar to methane. Although free hydrogen does occur as an intermediate product of petroleum maturation, it is extremely reactive and diffusive. Occurrence of hydrogen in a petroleum gas show is therefore most uncommon. Significant concentrations of hydrogen have been shown to result from deep-seated structural movement, but the most common origin is from the corrosion of aluminum drillpipe or of steel drillpipe in extremely low pH drilling fluids.

A serious disadvantage of the CCD is the tendency of the catalyst surface to become poisoned by the ac- cumulation of impurities and partial combustion products. This may result in a slow, progressive degradation of performance or a sudden, catastrophic loss, when, for example, silicon compounds are present in the mud. Regular detector calibration is essential to maintain reliable operation.

Flame Ionization Detector. The inherent limitations of the CCD resulted in a search for a more reliable detector technology. The most accepted and increasingly used is the flame ionization, or “hydrogen flame,” detector (FID) (Fig. 52.5).

One important difference between the flame ionization and the catalytic combustion principles is that the flame ionization method involves complete combustion of the sample. A small quantity of sample is introduced into a hydrogen/oxygen mixture that is continuously burning in a combustion chamber. The heat generated by the hydrogen flame is sufficient to initiate complete combustion of all hydrocarbons in the sample. A large oxygen excess is maintained relative to the small sample volume and saturation never occurs. The heat output of the hydrogen flame is the sum of the heats of combustion of hydrogen and the sample hydrocarbons.

Unfortunately, most of the heat produced is from the large volume flow of pure hydrogen. The small, dilute flow of hydrocarbons produces such a small proportion of the total heat of combustion that it cannot be measured accurately. Combustion heat then cannot be used as a measure of hydrocarbon concentration. Detection of the hydrocarbons instead relies upon an unusual in-

MUD LOGGING 52-5

termediate stage in combustion that only occurs in hydrocarbons burning at high temperatures. This involves the creation of unstable electrically charged anions and cations. By placing a positive electrode, or anode, in the form of a cylindrical chimney above the hydrogen flame, the negative anions may be collected and the resultant electric current used to determine hydrocarbon concentration.

The ionization/combustion sequence is a complex one that involves many intermediate and alternate reaction steps. The number of ions created, and therefore the current flowing, is in direct proportion to the concentration of the alkanes and to the number of carbon atoms in the alkanes (Fig. 52.6). The FID response in percentage EMA is, therefore, like the CCD, a richness indicator showing increases with increasing concentration and increasing alkane molecular weight.

The FID is totally selective for compounds containing carbon-to-hydrogen (C-H) bonds. Other gases and impurities in the sample stream produce zero or negligible response and do not degrade detector performance.

Although the detector response is effectively linear throughout all concentrations, the electrometer used to monitor and amplify the detector current has performance limits of linearity. Since mud log gas shows may vary from tens of parts per million (ppm) to tens of percent, both electrical signal attenuation and sample splitting are required to ensure low-range sensitivity and high-range linearity of FID response. In most modem instruments this is handled automatically, ensuring a higher degree of accuracy than manual sample dilution.

Gas Chromatography. In addition to a total gas detector, most modem logging units will also contain a gas chromatograph. This device allows the separation of the individual alkanes and their separated detection, giving a gas analysis of composition and concentration. While this analysis is of greater value than the total gas response in EMA, the chromatograph does not provide a continuous analysis but processes batch samples separated by a number of minutes. In drilling terms, this translates into separate analyses several feet apart. The chromatograph does not replace the total gas recorder in showing the fine detail and progressive changes in a gas show.

In gas chromatography, a fixed volume gas sample is carried through a separating column by a carrier gas, usually air. The column contains liquid solvent surface or a fine molecular sieve solid. By difference in gas solubility or by differential diffusion, the gas mixture becomes separated into its components, the lightest traveling most quickly through the column and the heaviest most slowly.

Depending on the nature of the column, each component will pass through and exit the column in a characteristic time. From the column, the components pass in turn to a detector, which may be a CCD, TCD, or FID. The detector is calibrated with a gas mixture of known composition and concentrations. A separate calibration factor for each component can be used for detector response as the components occur in turn.

Since heavier components take longer to traverse the column, the time and depth interval between samples is governed by the number of components to be analyzed.

0 0.2 0:4 0.6 0.8 1 :o

HYDROCARBON CONCENTRATION % IN AIR

Fig. 52.6-Flame ionization detector response.

In routine logging, a chromatograph usually will be set to cycle through continuous automatic analyses for methane, ethane, propane, isobutane and n-butane. This requires approximately 3 to 5 minutes. If heavier alkanes (e.g., pentanes) need to be detected, the automatic control is disengaged and the analysis allowed to continue for a longer period of time.

Infrared Absorption Detector. The third, and least used, form of detector is the infrared absorption detector. This instrument uses the principle that any chemical bond will absorb infrared energy of a specific frequency governed by the chemical nature and geometry of that bond. For example, methane contains four identical carbon-to-hydrogen (C-H) bonds. If a gas sample is ir- radiated with infrared energy at a frequency characteristic of this bond, the energy absorbed by the sample will be in proportion to the number of C-H bonds and hence to the concentration of methane in the sample.

All other alkanes contain C-H and carbon-to-carbon (C-C) bonds. Although these bonds are chemically identical, they vary in geometry and hence characteristic infrared frequency, depending on their position within the alkane molecule. Theoretically it should be possible to pass the gas sample through a series of test cells, testing for infrared absorption at a series of characteristic infrared frequencies. Combination of the results would provide a continuous analysis of both alkane type and concentration-i.e., the equivalent of a continuous chromatogmph.

Unfortunately, the C-H and C-C bonds show such a large number of minutely varying geometries that, instead of a series of discrete characteristic frequencies, a continuous band of overlapping absorptions occurs. At best, using a two-absorption cell system, it is possible to provide an estimate of methane concentration and total hydrocarbon concentration, in EMA. This result is com- parable to the result obtainable from a dual CCD system and inferior to the results from an FID-equipped gas chromatograph.

Detection of Nonhydrocarbon Gases. ’ The most commonly occurring nonhydrocarbon gases in petroleum exploration are CO*, HzS, helium, nitrogen, and hydrogen. As discussed previously, the occurrence of naturally produced hydrogen is rare. Helium and nitrogen also tend to have regionally or geologically


specific occurrences. CO2 and H2 S arc common trace or significant components of natural gases and equipment for their detection should be used on any exploration well.

Chromatograph-Thermal Conductivity Detector. The most versatile device for detection of nonhydrocar- bons is a chromatograph equipped with a TCD. By selecting an appropriate column material and length, any single component or combination may be separated. The TCD will provide a response to any gas that has a thermal conductivity different from that of the carrier gas. This response will differ for each sample gas/carrier gas combination but, by using gas mixtures of known composition, calibration curves for each component can be developed.

Best response and sensitivity is achieved when the maximum difference exists between the thermal conductivities of the sample gas and the carrier gas. Thermal conductivity generally declines exponentially with increasing molecular weight. Thus the light gases (hydrogen and helium) may be readily detected by use of air as the carrier gas. For the heavier gases (nitrogen, CO;, , and HzS) that have thermal conductivities closer to that of air, a lighter and higher thermal conductivity carrier gas must be used. Helium is a common choice but hydrogen also may be used if available.

An important consideration when assessing the reliability of analyses for nitrogen and CO2 is their presence in the sample caused by the introduction of air into the gas trap and the aeration of drilling fluid.

Air of normal atmospheric composition, dissolved and entrained in drilling fluid, will be introduced continuously into the borehole. In the hot downhole environment, corrosion and other oxidation reactions will deplete oxygen from this air resulting in a relative increase in nitrogen and CO* concentration. Oxidation of car- bonaceous material will further add to CO2 enrichment. Alternatively, the presence of corrosion inhibitors in the mud may deplete both oxygen and CO*. Regardless of the mechanism involved, oxygen depletion will increase with temperature and length of circulation time through the downhole system.

At the surface, this oxygen-depleted air and any gas recovered from the formation is mixed with ambient air at the gas trap. This air will vary in composition with the surrounding atmosphere-e.g., emissions from rig motors, vehicles, and others.

Any show of nitrogen or CO2 from the formation must be recognized above background concentrations, which will show some random variation and a progressive increase as the hole is deepened and mud circulation becomes hotter and of longer duration. Regardless of the analytical method used, precision of the ppm level cannot be provided by the analysis. When only trace quantities of gas are expected or when a precise compositional analysis is required, mud logging analysis of CO2 or nitrogen cannot be relied upon.

Of the nonhydrocarbon petroleum gases, HIS and CO? are the most significant. They are the most commonly occurring gases in high concentrations and because of their polar nature pose serious problems of corrosion of drilling and production equipment. H2S is

also toxic in relatively low concentrations. In many areas, detectors specific to these gases are considered standard mud logging equipment.

Infrared Absorption Detector. Continuous CO2 detection is best handled with infrared absorption. An infrared analyzer is used that is responsive to the characteristic frequency of the carbon-to-oxygen (C-O) bond unique to COz. Correction of atmospheric CO2 concentration is performed by alternately scanning two sample cells. One contains a sample from the gas trap and the other contains ambient air. Differential output provides a measure of CO2 concentration above atmospheric.

Tube-Type Detector. Several types of H2S detectors are used, all of which monitor a change resulting from the chemical oxidation of the gas. The simplest detector is the tube-type device in which the sample gas mixture is drawn at a controlled flow rate through a glass tube containing reactive lead acetate. The lead acetate, which is deposited on a substrate of high-surface-area silica gel granules, reacts with HzS to produce lead sulfide and changes from white to dark brown or black in the process:

Pb(CH3C00)2 +H2S-‘2CH3COOH+PbS.

Since the amount of lead acetate in any unit length of tube is constant, the tube may be graduated in terms of concentration of H2S in a fixed volume of sample.

The panel-mounted instrument has two tubes installed. Flow of sample from the ditch is constant through one of the tubes, and, if H2 S is present in the gas being evolved at the ditch, the lead acetate begins to discolor progressively from bottom to top (the direction of sample flow). Since the sample, and hence the discoloration, is continuous, this response is qualitative only. The discoloration indicates that H2S is present in only trace or in enriched quantities, but no estimate of actual concentration can be made.

As soon as this discoloration is seen, a warning must be given since even trace quantities of gas can be dangerous. A quantitative analysis can be made by switching flow to the second tube and introducing a timed sample. In this case, a fixed amount of discoloration occurs and the scale allows reading of the H2S concentration.

An alternative configuration for the tube indicator is in a small handbellows, often called a “puffer” or “snif- fer,” which can be used to sample the atmosphere in various locations around the rig.

Since the lead acetate reaction is not reversible, once the tube is used it must be replaced. The instrument cannot keep a continuous record of HzS concentration but only a series of individual measurements. This is a drawback, but not a serious one since any quantity of H 2 S in the atmosphere is both a health hazard and an indication that the mud system is totally saturated. Once HzS is detected, mud treatment to remove it must begin. Gas measurement is required to ensure that it is removed and does not reappear.

The tube indicator may be used to detect CO2 or any other gas for which a discoloring reactant is available. For CO*, hydrazine is used in place of lead acetate.

MUD LOGGING 52-7

Presence of CO2 is indicated by a purple coloration of the chemical in the tube:

CO2 +N2H4 -‘NH2NHCOOH.

The tube method, however, is poorly suited to continuous monitoring since there will be a uniform rate of discoloration by atmospheric CO2

Paper-Tape-Type Detector. A more sophisticated version of this detection principle uses continuous paper tape, impregnated with lead acetate, to allow continuous analysis and a quantitative electrical output for chart recording and activation of alarms.

The detector mechanism is similar in appearance to an open-reel tape recorder. Its operation and operating components are analogous to that of tape recording. Paper tape, a porous filter paper coated with an even concentration of lead acetate, is wound from reel to reel at a constant speed. The tape passes through a sample chamber through which gas from the ditch passes continuously. The tape will be discolored by an amount proportional to the concentration of lead acetate on the tape, the speed at which the tape is moving (both of which are constant), and the concentration of H2S in the sample. From the sample cell the tape passes to a detector where light from a collimated source is reflected from the tape to a photoelectric cell. The output of the photoelectric cell is readily calibrated in terms of H2S concentrations by passing through the system test paper strips with zones of different color that correspond to a range of known concentrations.

The paper-tape-type detector may be used for the detection of COz or other gases if a suitably impregnated paper tape is available. Unlike the tube indicator, it is possible to discriminate between a baseline of atmospheric discoloration and a true “show” above baseline.

Although the paper-tape-type is superior to the tube indicator, both suffer the disadvantage of requiring periodic replacement of the reactive material, lead acetate, and the possible degradation of the product in storage. Indicator tubes and rolls of paper tape are sup- plied in sealed, dated packages and should never be used if the seal is broken or the package is beyond its expira- tion date.

Solid-State Electrical Detector. The most modem Hz S analyzers involve use of a solid-state electrical detector. This device depends on the reversible reduction of metallic oxides by HzS as its means of detection. A semiconductor sensor element is exposed to a flow of gas drawn from the ditch. The surface of this element consists of a proprietary metallic oxide layer. In the presence of HzS, this layer will be partly reduced to metallic sulfides, and its electrical resistance will change:

(metal) O+HzS-+(metal) S+HzO.

This is an equilibrium reaction. If Hz S ceases to be present, the reaction reverses with the reoxidation of sulfides to oxides. At all times, the sulfide-to-oxide ratio (and

hence the electrical resistance) of the layer is a direct function of the concentration of H2S in the sample present in the vicinity of the sensor.

Alternative configurations of this device involve multiple installations with either samples being drawn from, or sensor elements located in, various locations around the rig with centralized monitoring and alarm functions. Locating the sensor in a remote location may cause problems if the sensor is exposed to potential damage or mistreatment. It does, however, remove the risk of loss of response resulting from gas dissolving in condensation in long vacuum lines.

The device has high reliability and accuracy and is widely used in the industry. There are, however, two deficiencies that should always be considered. The first and most important is that if the sensor is operated for a period of time without any H2S present, it tends to lose reaction speed. (It is important to note here that the sensor does not lose sensitivity! It will respond, within calibration, to the presence of H2S, but will respond somewhat sluggishly to the first appearance.)

For safety reasons, the sensor must be reactivated regularly by using a sample of H2S to maintain its reaction speed.

Second, the sensor will respond to certain organic sulfides that may be present in oil or result from mud ad- ditive decomposition. The response to these compounds is low but may result in a false H2 S show.

Soluble Sulfide Analyzer. One disadvantage common to all Hz S gas analyzers results from the high solubility of the gas in water. H2.S will not be liberated from the drilling fluid and will not be seen by a gas analyzer until a saturated solution of the gas exists. Since serious corrosion problems may be caused by low concentrations of the gas in mud and even a few ppm of the gas in air is a health hazard, it can be seen that by the time that HzS gas is detected at the surface, a major problem already has developed.

Early detection of H2 S requites analysis of the drilling mud. This can be accomplished by regular sampling and wet chemical analysis, but the mud logging service can provide continuous soluble sulfide analysis by using a selective ion electrode measurement system.

With this device, a sensor probe, which is immersed in the drilling fluid, contains pH (hydrogen ion) and pS (sulfide ion) specific electrodes and a temperature sensor. When HzS dissolves in water it will in part dissociate into bisulfide (HS -) ions and sulfide (S ~ -) ions. The solubility of H2S and the degree of dissocia- tion are controlled by the pH and temperature of the solution If these two parameters and the concentration of a single dissolved sulfide species are measured it is possible to deduce the concentration of all other species. In the soluble sulfide analyzer this is done automatically by a microprocessor. By using this device it is possible to detect H2 S and begin treatment to remove it from the mud without concentrations ever becoming high enough for gas detectors to be effective or for personnel to be placed at risk.

Geological Analysis

After gas analysis, the most important function of mud logging is the sampling and evaluation of drill cuttings.

52-a PETROLEUM ENGINEERING HANDBOOK

Even when the mud logging unit operator is not a professional geologist, the minimum requirement is for identification and brief description of sample lithology, estimation of reservoir properties (amount and type of porosity and permeability), and description of oil staining.

Sample Lag Time. Hydrocarbon and geological analysis depend on the representative sampling of drill cuttings and gases liberated by the cutting action of the drillbit. In interpreting the analytical results, it is necessary to account for the lag time and physical effects of the gas and cuttings travel from the bottom of the hole to the surface. ’

Lagging of samples is essential so that results may be reported or logged at the depth from which the sample originated (at the time the sample arrives at surface, the depth, of course, will be somewhat greater). Lag time may be obtained simply by calculating the time necessary to displace the total annular volume of drilling fluid as given by

van=v, -VP, ,..,.....,.....,...........(l)

qP van=- . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v ) (2)

an

and

D I/=-, . . . . . . . . . . . . . . . . . . . . . . . .(3)

VCWI

where V = annular volume, m3/m, VT = hole capacity, m3/m, VP = pipe capacity and displacement, m3/m, V, = annular velocity, m/s,

qP = pump output, m3/s,

tl = lag time, s, and D = depth, m.

Separate calculations must be performed for each annular section (drillpipe in casing, drillpipe in open hole, drill collars in open hole, etc.).

Calculated lag times ate used when first drilling out of casing or in hard rock areas where an in-gauge hole is expected. However, a calculated lag time cannot take into account capacity variation in out-of-gauge holes or variation in pump rate or efficiency (for example, when the pump is stopped to make a connection).

Determining and using lag in terms of pump strokes has distinct advantages over lag determined on a time basis. The counters tracking the cuttings up the hole stop automatically when the pump is stopped. Clocks would continue to run, and some subtractive factor would have to be introduced. The most important advantage, however, lies in accuracy. A lag determined in terms of an interval of time is correct for only one speed of the circulating pump (that speed at which the lag determination was run), whereas the lag in pump cycles is accurate for any pump rate.

The lag can be determined by placing a tracer in the drillpipe at the surface when the kelly bushing is “broken off,” allowing the tracer to be pumped through the hole and back to the surface, and counting the number of strokes requited of the circulating pump to make this circulation. From this total pump stroke count, the number of strokes required to pump the tracer down through the pipe to the bottom of the hole is subtracted. This figure is calculated on the basis of the capacity of the drillpipe and the displacement of the circulating pump. The result is the “lag stroke.”

Various materials (such as whole oats, barley, or strips of colored cellophane) may be used as tracers and picked up on the shaker screen for approximating the lag. Under ordinary circumstances, however, calcium carbide placed in the drillpipe will react with the mud to form acetylene. This gas will be picked up by the mud gas detector and is the most convenient and reliable method for determining the lag. Acetylene gas appears as wet gas on the gas detector and is easily distinguished from methane produced from the formation.

Representative Cuttings Samples. There is no substitute for representative cuttings samples accurately correlated to the depth from which they came. They are the required supportive data for the evaluation of any mud logging, geological, geophysical, or engineering data. Every rig has a shaker screen for separating the cuttings from the mud as they reach the surface. The shaker screen may or may not be a good place from which to take cuttings samples. 3-5 If the shaker screen is used, a board or catching box should be placed at the foot of the screen for collecting composite samples. This becomes especially important where drill rate is low, to ensure that the sample collected is representative of the whole interval drilled and not just the final few inches.

Where a traditional “rhumba” shaker is used, differences in flow through the possum belly (ditch at the rear of the shale shaker) will result in density and size sortings of cuttings across the various screens. This sorting can be of assistance to the logging geologist in par- tially separating large cavings from the smaller bottomhole cuttings. However, great care must be taken to ensure that a representative sample is caught. Where a modem “doubledeck” shaker is used, cuttings on both the upper and lower screens should be sampled.

A sampling depth interval should be set that thz mud logger can be expected to maintain while keeping up with other responsibilities. Sample intervals can be shortened as the hole is deepened and drill rate falls. The mud logger should never allow more than 15 minutes to pass between catching samples. For example, if the sample interval is 10 ff and the drill rate is 10 ft/hr, the mud logger should take four scoops of samples over the hour to fill the sample bag for the interval. Special samples should always be taken whenever background gas changes are seen or the lag time after drilling breaks occur. If a board or catcher box is used, it must be cleaned off after each sample is taken.

Samples should be taken from the desilter or desander outlets whenever these are running. In this way, the logging geologist can establish the quantity and appearance of sand and line solids commonly contaminating the mud system. If an unconsolidated formation is penetrated,

MUD LOGGING 52-9

sample from the desander will contain both formation sand and mud solids. The logging geologist must be able to discriminate between these.

Washing the cuttings in many areas, however, par- titularly areas and zones of tertiary sands and shales, is

Washing and preparing the cuttings to be examined are probably as important as the examination itself. In hard rock areas, the cuttings are usually quite easily cleaned, in which case washing is a matter of merely hosing the sample in a container of water to remove the mud film.

more difficult and requires several precautions. The clays and shales present are often soft and of a consjsten- cy which goes into solution and makes mud. Care must be taken to wash away as little of the shale as possible, and, in determining the sample composition, to take into account that which is washed away.

After washing the cuttings to remove the mud, they are washed through a 5-mm sieve unless doing so will further cause excessive loss of shale or clay. It is generally considered that the cuttings will pass through the S-mm sieve, and that the material that does not is cavings and may be discarded. However, the material that does not pass through should be examined for sand cuttings. If they should be present, these afford an excellent oppor- tunity for study of larger-than-normal cuttings chips.

Cuttings from wells drilled with oil-based or oil- emulsion muds are usually more representative of the drilled formation than cuttings drilled with water-based mud because the oil emulsion prevents sloughing and dispersion of clays and shales into the mud. At the same time, washing and handling cuttings drilled with this type mud poses somewhat of a problem; they cannot be cleaned by washing in water alone. It is usually necessary to wash the cuttings first in a detergent solution to remove the mud. Some of the liquid commercial detergents available may be used. In extreme cases, it may be necessary to wash the cuttings first with a nonfluorescent solvent such as naptha, and then wash them in a detergent solution to remove the solvent. Use of a solvent is not advisable unless absolutely necessary because of the risk of removing any oil staining present.

An oven mounted on the wall of the logging unit can be used to dry a portion of the cuttings sample after it has been washed, but some of the washed cuttings are examined wet under the microscope. A sample of unwashed cuttings also is required for cuttings analysis in the blender. Although these cuttings should not be rigorously washed, a light rinsing to remove surface drilling mud film is advisable.

The logging geologist should extract a small amount of sample from each stage of the sample preparation process. From examination of all samples, an accurate estimate of sample composition can be produced. 3 Once the percentages of the various constituents have been estimated, the sample description in logical order should contain (1) rock type, (2) color, (3) hardness (indura- tion), (4) grain size, (5) grain shape, (6) sorting, (7) luster, (8) cementation or matrix, (9) structure, (10) porosity, (11) accessories, and (12) inclusions.

Only a visual sample examination usually is required at the wellsite in elastic (sand/shale) formations. In carbonates, other tests may be required to determine the chemical and physical nature of the rock. The simplest of these is to test cuttings with dilute hydrochloric acid; the

rate of reaction, which is rapid for calcite and slow for dolomite, provides a guide to relative composition.

sample.

This test can be made more quantitative by use of a calcimeter. In this device a weighed sample is treated

In more complex mixed carbonates and sulfates (e.g.,

with acid in a sealed reaction chamber. Reaction is monitored by measuring either the volume or pressure of evolved CO;! over time until reaction is complete. Out- put is percentage of calcite and dolomite in the rock

anhydrite and gypsum), a chemical stain kit may be used. Small samples of washed drill cuttings are spot- tested with a series of chemical test solutions. Characteristic coloration of a test solution is indicative of the presence of a particular mineral in the sample.

Many excellent texts are available that discuss the geological aspects of mud logging. These include Low, 6 Maher, 7 and McNeal. * Since this chapter deals primarily with the technology of mud logging, they are not discussed further here.

Hydrocarbon Content of Samples

In addition to a geological evaluation, cuttings samples must be tested for hydrocarbon content. A blender or cuttings gas analysis must be performed on every sample caught. This involves disintegration of a sample of cuttings in a blender, extraction of a sample of liberated gas, and injection into a total gas analyzer. This can be performed by manual extraction with syringe and injection into the unit’s online gas analyzer. However, for speed and continuity of operation, modem logging units use automatic extraction and injection into an independent catalytic combustion cuttings gas analyzer.

As soon as a representative cuttings sample has been taken, a measured amount (100 cm3 in a measuring cup) of unwashed sample is placed in the blender jar and covered by 600 cm3 of water, then blended for 30 seconds and left to stand for another 30 seconds before taking a gas sample. If the hole is caving badly, the amount of cuttings may be increased but should be consistent-especially before and through a show. With hard carbonates, low-porosity sandstones, or similar reservoir rocks that cannot be efficiently pulverized by the cutter blades (40 to 60 seconds’ blending is recommended), the blender jar should be allowed to stand for 2 or 3 minutes before taking any gas readings. After the gas analysis is performed, the water should be inspected for oil signs or petroleum odor. Any droplets can be skimmed off for examination. The crushed rock material also may be of value in clarifying lithological evaluation.

The blender is a good evaluation tool because it gives some indication of the quality of the reservoir with respect to the porosity and the GOR. A good porosity sandstone generally will be well-flushed by the time it reaches the surface, so the amount of cuttings gas obtained will increase proportionately to the decreasing porosity. This is also true with a sucrosic dolomite or high-porosity limestone such as chalk. However, if the reservoir is a fractured carbonate, etc., with all the oil and/or gas in the fractures, little or no cuttings gas will be recorded and the use of the blender as a porosity indicator is of limited value, because future production is


going to be more dependent on the complexity of the reservoir fracturing than the inherent porosity and permeability of the rock itself.

In oil reservoirs, gas is normally in solution with the oil, and the agitation of a covered sample provides an excellent index of the amount of gas with the oil, which is significant in view of the gas already recorded from the ditch. A high cuttings gas with an oil show should be treated as a very significant show and should be one of the more important factors to consider in the overall evaluation.

When large intervals of reservoir rock are cored, the blender readings obtained are not likely to be as infor- mative as those obtained if the section had been drilled normally. Generally, the amount of sample is reduced because the center is still in the core barrel. With the often slower drill rate, the percentage of cavings may be increased. Also, if a diamond head is being used, the rock will be coming back in a very ground-up and often badly altered state. Thus, if the geologist is agreeable, representative loo-cm3 samples from the more broken- up parts of the recovered cores may be blended with water, and any readings can be used to supplement the readings obtained during the actual coring.

Inspection for liquid hydrocarbons should be made at the microscope (oil-stained cuttings), the blender jar (petroleum sheen and odor after blending), and in an ultraviolet light inspection box (fluorescent oil droplets on cuttings and diluted mud samples).

Visible oil stain and color is an important indication of oil presence and type as are ultraviolet fluorescence in- tensity and color, grading from dull brown for the heaviest (residual or wet) oil to bright blue-white for light oils and condensate. However, crosschecking of observations is essential to confirm the presence of oil. Many mud additives, contaminants, minerals, or rig floor debris will have an oily appearance or odor and may fluoresce under ultraviolet light. Only if visible stain and ultraviolet fluorescence yield the same conclu- sion is oil confirmed. For example, samples con- taminated with pipe-dope will have a dark oily ap-

Fig. 52.7-Comparative results of REII, OSA, and THA

pearance suggesting heavy oil. However, the same cuttings examined under ultraviolet light will show a bright blue-white fluorescence characteristic of the highest gravity. This incompatability allows the identification of a contaminant and avoids the logging of a false show. A good mud logger should examine all mud additives stocked at the wellsite and determine, before their use, their characteristic properties and appearance when mixed with drilling mud or cuttings.

If a true oil stain is identified, a single, representative cutting should be tested with an organic solvent. This is the “cut test.” Solvent cut is valuable in assessing fluorescence and allows deductions to be made of oil mobility and permeability of the reservoir. By removing the oil from the colored background of the cutting, the solvent allows a better estimate of fluorescence. The way in which the solvent cut occurs (e.g., instantly for high- gravity oils, more slowly for more viscous lower-gravity oils, or irregularly streaming from limited permeability) also yields useful information. If no cut can be obtained from a washed cutting, the test should be repeated on a dried cutting, a crushed cutting, or after application of dilute hydrochloric acid. This will produce the required cut and yield further evidence on permeability or effective porosity. After the cut solvent has evaporated, a residue of oil remains in the cut dish, displaying the oil’s natural color.

Finally, if sufficient oil is present, it may be possible to determine its refractive index. Just as oil stain color and fluorescence progressively change with oil type, refractive index correlates well with oil gravity. Portable refractometers that require only a small droplet of sample are available for use in the mud logging unit. By using a small quantity of oil (skimmed from the surface of the blender jar or a diluted mud sample), a very reliable estimate of oil gravity can be obtained.

Geochemical Analysis More sophisticated analyses of hydrocarbon and hydrocarbon source material involve the principle of pyrolysis-thermal decomposition of a sample in an inert atmosphere. Three such devices are presently available: the Rock-Eva1 II*” (RE), the Oil Show Analyzer’” (OSA), and the Therrnalytic Hydrocarbon Analyzer’” (THA). All these devices use variations of the lnstitut FranGais du Pitrole-Centre de Recherches du Groupe Petrofina (IFP-FINA) temperature-programmed pyroanalysis method developed by Espitalie. 3,9 The process involves the heating of a weighed rock sample through an increasing temperature program in an inert helium stream. Since combustion cannot occur, the helium carries away from the sample hydrocarbons and CO2 resulting from the thermal volatilization of petroleum and organic source material in the rock. These evolved gases may be analyzed by flame ionization and thermal conductivity detectors. The amount of gas expressed as milligrams per gram of rock, the evolved gas, and the time and temperature of evolution may be used to characterize the richness and type of a reservoir or source rock.

The differences between the three devices are shown in Fig. 52.7. The RE 11 uses a uniform temperature ramp of 25”Umin up to 550°C. The helium stream carrying evolved gases passes to a CO2 trap and then to an FID.

MUD LOGGING 52-11

On completion of the pyrolysis the trapped CO2 is passed to a TCD. The output showing temperature, FID and TCD response is called a “pyrogram.”

The RE II pyrogram characteristically shows two distinct peaks in FID response. The first, SI , represents true hydrocarbons, oil and gas, volatilized from the sample. The second, 52, represents hydrocarbons generated by the thermal cracking of hydrogen-rich organic source material, kerogen, in the sample. The temperature, T maxi at which the peak of S2 occurs is indicative of the maturity of the kerogen. Mature kerogen, capable of generating oil or gas, will have a T,,, in the range of 435 to 470°C. A lower T,,, indicates immature kerogen and a T,,, above 470°C indicates postmature material that has already yielded the majority of its hydrocarbon product.

The TCD response, S3, represents the yield of CO2 from the thermal cracking of oxygen-rich kerogen in the sample. A comparison of S2 and S3 provides the relative hydrogen/oxygen richness of the kerogen. This is useful in estimating source type. Hydrogen-rich kerogen is prone to rich oil yields, whereas oxygen richness gives more gas-prone and lower-yield kerogen.

Following completion of pyrolysis the sample is further heated in an oxygen atmosphere causing the complete

The oil show analyzer (OSA) differs from the RE II in that it uses a nonuniform temperature consisting of two temperature steps followed by a temperature ramp.

combustion of all remaining organic carbon in the sample.

The OSA pyrogram generally shows three characteristic peaks in FID response with SO and Sl corresponding to the two temperature steps and representing the splitting of the RE II Sl peak into a lower- temperature (gas-indicating) peak and a higher- temperature (oil-indicating) peak. The S2 peak and T,,, are the same as those seen in RE II. S4 represents CO2 produced by pyrolysis (S3 equivalent) and by combustion. Combination of the pyrolysis and combustion gas products provides a measure of the total organic carbon content or the gross organic richness of the rock.

RE II has become widely used as a laboratory instru ment and both it and the OSA have seen use in the mud logging unit in frontier exploration. The restriction on their wider implementation in mud logging has been the high complexity (and price) of these instruments, which has limited their use to the most advanced logging units and demanding exploration environments.

The THA, a much simpler device, is better suited to routine mud logging services. It uses only an FID and a temperature program similar to the OSA pyrolysis phase (without the final combustion phase). The THA pyrogram provides SO, Sl, S2 and T,,, . Neither CO;! analysis, S3, nor S4 is available from the THA.

The Modern Mud Logging Unit There are six basic requirements for a modem mud logging unit* based on the previous discussions.

1. A total combustible gas analyzer using catalytic combustion or flame ionization detector.

2. A gas sample dilution system, allowing maintenance of linear detector response at high gas concentrations or a backup thermal conductivity detector.

3. An automatic cycling chromatograph capable of

isolating and detecting methane, ethane, propane, butane, and isobutane or a second, low-voltage catalytic combustion detector, allowing discrimination of “total gas” from “petroleum vapors.”

4. A separate cuttings gas analyzer, allowing gas analysis from blended cuttings samples.

5. A microscope and ultraviolet light inspection chamber for the identification and description of lithology and liquid hydrocarbons.

6. A pumpstroke counter, which, in conjunction with calcium carbide lag tests, allows gas readings and cuttings samples to be lagged back to correct drilled depth.

In addition, the unit requires a drilling depth and time recorder for the determination of sample depth and the calculation of rate of penetration, an important rock strength/porosity indicator. Ideally, this should be independent of the driller’s depth recorder.

Although pressure control is not a standard function of mud logging (see Petroleum Engineering Services), the

Since mud logging samples (gas, oil, and cuttings) are extracted from the mudstream, changes in mud chemistry and rheology must be considered when evaluating mud log results. The logging unit should be equipped to perform basic mud tests-e.g., mud balance, Marsh funnel, sand test kit, and filter press. Laboratory glassware and chemicals are required to perform chemical tests and titrations on cuttings and mud filtrate samples.

mud logger, by continuously monitoring mud gas content, should be aware of situations of potential drilling hazard. It is therefore usual for the mud logging unit to be equipped with a level monitor for the active mud pit. This allows the mud logger to be a second line of defense, after the driller, in detecting a well kick or loss of circulation.

The Mud Log Format ’ Fig. 52.8 shows a typical modem mud log. There are currently no industry standards for mud logs, and presen- tation varies among operators. However, the track order commonly follows that shown in the example.

Truck I is used for rate of penetration (ROP). Also included in this column are items of drilling data that may affect interpretation of the log (bit types, changes in drilling parameters, circulation breaks, etc.).

Track 2 is for depth notation and for symbolic representation of special evaluations (for example, cored or tested intervals).

Truck 3 is a graphical representation of formations penetrated. Usually the column is subdivided into 10 equal columns and graphic symbols are used to represent 10% increments of lithology types seen in cuttings. Unlike other tracks on the log, the lithology track is not a calibrated physical measurement but a subjective assess- ment. Care should be taken to establish rules of drafting

- acceptable to the preparer and user of the log. Even after removal of cavings and contaminants, a

cuttings sample is not truly representative of a single depth interval. Variation in particle size and density cause differences in annular recovery rate and mixing of cuttings in the annulus. A true cuttings percentage will never show sharp formation boundaries as a result of this mixing. For example, a thin sandstone within a massive


XL MUD LOGGING COMPANY

COMPANY ABC OIL COMPANY OF THE NETHERLANDS

WELL DESMOND Xl

F,ELD ANDORRA REG,ON DUTCH NORTH SEA

COORDINATES 5’ ‘0’ 50” N 02 1530’E

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MUD LOGGING 52-13

shale with sharp boundaries shown clearly by ROP and total gas analysis may appear from cuttings to be a sandy shale horizon of much greater vertical extent.

A geologist may use all available data to prepare an interpretive lithological log. That is, in the previous example, to sharply show the sandstone boundaries as indicated by ROP. Sometimes a mud logger will attempt to add some degree of interpretation to a cuttings log. Again, in the example the mud logger would show the presence of sand in all the cuttings samples but exag- gerate the percent sand in the sample coinciding with the higher ROP.

This “semi-interpretation” may result in confusion when later sample examinations are compared with the mud log and, in my opinion, mud loggers should be in- structed to prepare a true cuttings log representing the percentages of lithologies actually seen in the sample. If the mud logger is geologically qualified and the operator’s geologist requires geological interpretation, then an interpretive lithological log should be prepared as an additional track on the mud log.

Track 4 presents the results of hydrocarbon analyses. It may consist of one single width track but most often is subdivided into two or more separate tracks, as in the example. Track 4 will include the results of total gas, cuttings gas, and chromatographic analyses and when oil shows occur, an estimate of oil show quality and oil cut will be added. Supplementary gas analyses (helium, hydrogen, CO 2, or H 1 S) also may be added to this track or plotted on a supplementary log.

Track 5 primarily is used for brief sample descriptions. Also included in this track are mud test results, casing and cementation records, hole deviations, carbide test results, and many other operating data used in interpretation of the mud log. On wider format logs, Track 5 also may be subdivided to add an interpretive lithology and an extra data track to be used for the results of special analyses or calculations.

Interpretation The object of logging drilling-mud gas shows is to iden- tify potentially productive oil and gas horizons. While such zones often may be indicated by major events-e.g., large gas and fluorescence shows-more critical interpretation is required to avoid false alarms or missed opportunities.

Total Gas shows The magnitude of a total gas show is not in itself a conclusive indication of show quality. Gas detected at the surface originates in three ways: (1) from the disintegration of a cylinder of rock by the drill bit as the hole is deepened, (2) from the influx of gas from previously drilled formations exposed in the borehole wall, and (3) from the drilling mud itself in the form of recycled oil and gas and decomposition of mud additives.

In extreme cases (for example, in long, geopressured shale sections or when using oil-based drilling fluids) influx or contamination may constitute the majority of gas seen at the surface. In such circumstances the magnitude of a gas show from a potential reservoir must be evaluated against the established background gas level from overlying sediments. Gas shows from relatively

thin horizons may be submerged in a high background and not identified from total gas alone (Fig. 52.9).

Even gas reliably identified as resulting from a drilled interval may be misleading as a show-quality indicator. Factors that affect the magnitude of a gas show include the volume of the rock cylinder crushed in the drilling process, controlled by bit diameter and ROP and dilution of liberated gas in mud (i.e., the flow rate of drilling mud passing bottom as the hole is cut). Thus, gas show magnitude will be expected to increase in larger diameter holes, at higher ROP’s, or at reduced mud flow rate (Fig. 52.10).

A simple technique is available to remove these factors from evaluation by normalizing gas show magnitude to a standard or “normal” set of drilling conditions:

R, l- ’ ” R

(4) OB

where G pOs = observed total gas, %, G,, = normalized total gas, %, 4oB = observed mud flow rate, m”/s, 9n = “normal” mud flow rate, m’/s,

d OB = observed bit diameter, m, d, = “normal” bit diameter, m,

R it

= observed ROP, m/s, and = “normal” ROP, m/s.

Once a “normal” set of conditions are selected, the equation can be readily simplified giving

0.010 G,, = Gpo~

R OB

and -

G,, = 0.0126 Gpos90B

(d,B)2 RoB ) . . . . . . . . . (5)

where 9n = 0.050 m3/s (793 galimin), d, = 0.251 m (9.875 in.), and R, = 0.010 m/s (118 ft/hr).

Normalization can be very useful in correlation of gas shows between wells drilled with very different programs. However, it should be remembered that normalization cannot remove the effect of influx and contamination; nor does it account for varying gas trap efficiency with ambient conditions.

Finally, remember that the gas produced by drilling is liberated by the crushing of material at the bottom of the hole and is representative of the fluid composition within the rock pore space at the time of impact. Remember that oil and gas flow from a producing well; they are not mined. The presence of a fluid within a rock is not


Fig. 52.9-Mud log total gas shows.

Fig. 52.10-Variation of total gas with drilling parameters.

necessarily indicative of productivity of that fluid ,fram that rock. Comparison of total gas analyses from mud and cuttings and chromatography can yield useful clues as to the productivity of a hydrocarbon-containing formation.

Total gas from the cuttings blender test is a good indicator of fluid mobility. As the crushed rock cuttings are carried to surface and relieved of formation

hydrostatic pressure, exsolution and expansion of gas should effectively flush the cuttings, leaving only a small volume of residual fluid at the surface. When higher cuttings total gas, relative to ditch total gas, is observed, this is an indication that this flushing has been impeded. An obvious explanation is that the rock lacks sufficient permeability to allow gas expansion and flushing. However, residual low-gravity oil or tar will have a similar effect in impeding gas exsolution and escape. In- spection of cuttings lithology, fluorescence, and the cut test should provide confirming evidence (Fig. 52.1 I). For example, strong cementation or shaliness in the cuttings would be indicative of low permeability, whereas dark or dull oil stain and fluorescence with a slow cut or absence of cut is more indicative of heavy oil.

At the opposite extreme of mobility, a formation may be so permeable that it is flushed effectively with mud filtrate even before being drilled. On recovery to surface neither mud nor cuttings will contain hydrocarbons. In- deed, no cuttings may be seen since such formations are commonly unconsolidated and disintegrate on recovery.

In this circumstance the first observations will be a sharp increase in rate of penetration followed, after the lag time, by a “negative” gas show; total gas declines below the original background. Testing the desander ef- fluent or a mud sampling probably will show an increase in loose sand grains. The negative gas shows confirms only the excellent permeability, and for this reason alone the zone deserves closer inspection when a resistivity log is available. No evidence is available of the formation’s fluid content from the mud log.

Most potential reservoirs fall between these two ex- tremes: producing (1) a positive gas show and (2) cuttings blender gas, depending on permeability and oil

MUD LOGGING 52-l 5

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gravity. Color and fluorescence of the oil stain and results of the cut test are indicative of oil type. However, note again that presence of hydrocarbons in the rock and even presence of porosity and permeability are not conclusive evidence of hydrocarbon productivity.

Chromatogram Interpretation

The hydrocarbon chromatogram is often a useful guide to reservoir productivity. It is not the actual amount of any one alkane that is significant but the relative amounts of light and heavy components characteristic of the overall reservoir fluid. Such characteristics normally can be recognized on the mud log itself. An aid to this can be the calculation and plotting of the numerical ratios of the values of the various hydrocarbons (e.g., C2/C I) C3/C1, etc.). Such gas-ratio plots will often yield distinctive “character” or “events” not always immediately evident from the chromatogram itself. However, interpretation of the plots depends on the same logical procedures.

Most petroleum hydrocarbons originate from a similar organic source and proceed in their maturation by a similar temperature- and pressure-controlled physico- chemical process. For this reason, petroleum accumula- tions, although markedly different in composition, tend to show a spectral relationship to each other in terms of the type and amount of hydrocarbon species present. Therefore, although two crude oils of 30”API gravity may be extremely different in total composition, they will contain some similar components in similar compositional relationships to each other. Since petroleum maturation continues by the continuous “cracking” of complex branch molecules into simpler straight chain molecules, these significant relationships are readily seen in the petroleum gases methane through butane. Thus, study of chromatographic analysis of these gases often may lead to a gross estimate of the type and quality of the reservoir.

At low temperatures and shallow burial, biological and catalytic decomposition of organic debris results in a low-yield production of methane and CO2 Though the CO2 will dissolve in and migrate with pore waters, the methane will accumulate in porous zones either as free gas or in solution in water. Such zones will yield im- pressive gas shows when drilled, but with few excep- tions will produce only gas-cut water.

It is a reasonable general rule that a gas show containing methane as the only significant component is not commercially productive and is unworthy of further evaluation. However, it also should be remembered that exceptional cases do occur, including the southern North Sea nonassociated gas reservoirs that produce +94% methane.

At higher temperatures, organic material first polymerizes to form kerogen, which is then hydrogenated and cracked with increasing temperature to form bitumens, tars, and progressively higher-gravity oil and gas. Associated petroleum gases are fragments of this cracking process and as cracking continues, the proportion of light to heavy gases increases in a manner similar to the lightening of the liquid hydrocarbon. This fractionation of gases and liquids continues during the migration of the hydrocarbons from source to reservoir.

The end result of this process is reflected in a gas show chromatogram. A gas-productive interval will show predominantly methane and ethane with only traces of the heavier alkanes. Oil productivity is signaled by the enrichment of the heavier alkanes, especially propane. Decreasing oil gravity is reflected by progressively greater proportions of propane and the butanes. In lower- gravity oils, the concentration of these gases may exceed that of ethane. But all productive horizons will contain methane as the dominant alkane. Zones in which methane represents at least half of the total gas usually contain heavy residual oil from which the lighter gas and liquid fractions have migrated, leaving an immovable, nonproductive fluid.

These general rules of chromatograph evaluation can prove useful in reservoir evaluation but of course should not be used in isolation. Conclusions regarding oil gravity and mobility should be compared with the results of blender tests, cuttings examination, fluorescence, and cut tests. Furthermore, evaluation should proceed from the prior-show baseline values and throughout the show interval. Considering the variables inherent in the drilling, transportation, and extractions of samples, no con- clusion may be drawn from a single sample or analysis.

Conventional Mud Log The conventional mud log offers more drilling and formation evaluation data in a single form than any other data source. Many of these data are subject to uncon- trolled variables in the measurement technology and by the very nature of borehole environment. As a result, no simple conclusive rules of quantitative log evaluation are available. However, integration of all the data on the log with geological and regional experience can make the conventional mud log a most powerful exploration tool.

Petroleum Engineering Services Geopressure Evaluation The petroleum engineering functions of mud logging developed from the introduction of a number of pressure evaluation techniques during the 1960’s. These techniques are practiced conveniently in the logging unit and in some cases use data or equipment already available in the unit. Also, interpretation of the resultant data rc- quires the same integrative approach, using drilling data and geological evaluation, as required in mud log interpretation. Unlike mud log evaluation, however, pressure evaluation techniques are able to provide reliable quantitative estimates of formation parameters, such as pressures and porosity. lo

Drilling into a geopressured zone causes a change in a number of basic formation/drilling relationships. This change is usually a reversal of a gradual de th-related trend in a lithologically uniform formation. IP Compac- tion increases uniformly with depth in a normal pressured clay rock. A geopressured zone may be poorly compacted relative to those zones overlying it. Porosity and water content decrease uniformly with depth in a normal pressured clay rock. A geopressured zone in which dewatering has been slowed will show a reversal in the trend, with increased water content and increased porosity. Other factors relating to fluid movement, such as ionic concentrations, hydrocarbon saturations, etc.,

MUD LOGGING 52-17

may be different in geopressured zones. Differential pressure across bottom is the difference between the drilling mud hydrostatic pressure and the fluid pressure in pores of the undrilled formation at the bottom of the hole. Since drilling mud usually is denser than formation fluids, this difference will be positive and will increase with depth. In a geopressured zone, the formation pore pressure is abnormally high and the differential pressure across bottom will decline or even become negative.

Thus, any measureable parameter that reflects any or all of these factors may be used as a means of interpreting changes in formation pressure and eventually as a means of evaluating and obtaining quantitative estimates of formation pore pressures.

Gas Analysis. The incursion of formation fluids into the borehole may result from a number of causes, some but not all of which result from an underbalanced condition-either temporary or permanent. ‘* If an underbalanced condition exists, there will be a natural tendency for fluid to flow from the formation into the borehole. With a formation having good porosity and permeability, this flow will be massive and a kick will occur. Such a kick will be indicated by the incursion of formation fluid downhole, causing the expulsion of mud from the borehole at surface. Were this to continue, a blowout would result. It is the logging geologist’s responsibility (other duties permitting) to monitor the mud pit level and to report any unpredicted or unexplained level changes. A massive incursion of fluid resulting in a well kick is unlikely to be misinterpreted as a gas show. In fact, if the hole is full, the kick should be recognized by a rise in pit level long before the fluid causing it has time to appear at surface.

However, minor incursions caused by slight or temporary underbalance, or where insufficient permeability to provide a sustained kick exists, do occur and must be interpreted correctly.

When an underbalance sufficient to cause a kick exists but there is insufficient permeability to sustain a massive fluid influx, a steady fluid “feed-in” may result. If this minor flow is from a discrete formation already cut, it will be noticeable - producing a sustained minimum gas background even when circulating but not drilling. If this is the case, the logging geologist should make a note of this sustained circulating gas on the mud log.

If the feed-in is from the formation currently being drilled, then as a greater and greater area of formation in the borehole wall is exposed by drilling, increasing flow will take place. If this is the case, the mud gas will exhibit a sustained minimum when circulating but will consistently rise as drilling proceeds. Cuttings gas will in- evitably be high relative to mud gas since it is only the lack of permeability that is preventing the feed-in from becoming a kick. Where permeability is effectively ab- sent (e.g., in clays or shales) even a minor feed-in cannot take place. Fluid pressure in the rock will gain access to the borehole by the opening of pre-existent microfrac- tures and partings in the rock. The result will be the caving or sloughing of rock fragments into the borehole, accompanied by a small amount of gas. A minimum gas background and, in this case, cavings recovery exist when circulating without drilling.

Fig. 52.12-Connection gas indicating underbalance.

Circulating bottomhole pressure is higher than when the mud is static. This is caused by annular pressure losses when circulating. It is therefore possible for a feed-in, caving, or even a kick to result because of a resultant underbalance when circulation is stopped. Fur- thermore, pressure is further reduced because of the swabbing effect when pipe is moved upward-e.g., when making a connection. The literal meaning of “swabbing” is the pulling of a full-gauge tool from the hole, acting like the plunger in a syringe and initiating fluid flow into the borehole. Swabbing by moving the drillstring does not work in this way. When pipe is pulled upward, the high-viscosity gelled mud will attempt to move with the pipe, thus reducing the effective hydrostatic pressure acting on the borehole wall. Pressure reduction is a function of pulling speed, mud rheology, and annular diameter. The important consideration is that pressure reduction takes place not just below the bit but at all points in the open hole.

Downtime gas or connection gas is a gas show resulting from the momentary underbalance caused by pump shutdown and/or pipe movement. It can be recognized by the occurrence of discrete gas show appearance at, or slightly less than, the lag time after circulation recommences. This is gas actually being produced by the formation and, while not being plotted on the mud log, the value should be reported on the log because it is indicative of formation permeability and fluid content. When a connection gas occurs, the logging geologist also should check a flowline mud sample for evidence of produced oil or salt water with the gas. The incidence of connection gas should be reported to the


:ONNE GA:

iC SE

TOTAL GAS I NORMALIZED I

Fig. 52.13-Normalized total gas.

drilling supervisor, who may choose to increase mud density in response to the indicated underbalance.

It is important to remember that the entire openhole section will be underbalanced by swabbing. The connection gas may not come from the bottom of the hole but from some horizon above. In fact, two or even more connection gases may result from a connection. For this reason it is important that lag time and annular velocities should be identified accurately by the logging geologist so that connection gases can be identified with the producing formation and the mud log annotated accordingly.

Drilling into a permeable reservoir with an underbalance is potentially dangerous because a kick may result. Even if a kick does not occur immediately, the hazardous situation will be marked by an increasing feed-in as more formation is drilled, accompanied by progressively larger connection gases (Fig. 52.12). The condition should be reported by the logging geologist and noted on the mud log. If increases in mud density alleviate or remove the effect, this should also be noted on the mud log in explanation of the consequent reduction in gas.

Fig. 52.13 demonstrates the effect of varying differential pressure on gas show magnitude. The total gas curves for two wells drilled through a similar section are shown. The data for both wells have been normalized to reduce the effects of hole diameter, ROP, mud pump output, and surface extraction efficiency. Well A was

drilled with a constant mud density, whereas in Well B mud density was controlled to maintain a constant positive differential pressure (overbalance).

In the upper portion of the section, the two gas curves are similar and the normalized gas curves coincide almost exactly. In the lower portion a progressive deviation between the two wells is seen that is somewhat reduced but remains evident even in the normalized curves. We can interpret this as being caused by the penetration of a transition zone into a geopressured zone.

In Well A, maintaining a constant mud density results in a decreasing overbalance and eventually an underbalance or increasing negative differential pressure. Connection gases occur and become larger with deeper penetration. Additionally, feed-in of gas from the underbalanced borehole wall causes an increase in background gas that, since it is not a product of freshly cut formation, cannot be accounted for in the normalization calculation.

Well B, on which a constant overbalance was maintained by increases in mud density, did not show increases in gas background or connection gases. Indeed, if any zone showed good permeability, the overbalance may have resulted in flushing gas away from the borehole and a reduction in observed total gas.

By careful observation of these phenomena, a fairly accurate log of differential pressure (and hence pore pressure) may be obtained. This information should be used in conjunction with the other techniques described in the following paragraphs.

MUD LOGGING 52-19

Cuttings Evaluation. During the normal mud-logging process, cuttings are sieved and graded to a size assumed to be representative of drilled cuttings. The larger fragments are cavings from the walls of the borehole and play no part in the compilation of a lithological log.

In geopressure evaluation, these cavings play a major role. The presence of cavings in the sample indicates that the borehole wall is unstable. The most noticeable and usually most predominant cavings are those of clay, shale, or calcareous lithologies. Coal, however, will cave as a matter of course, hence interpretations should not include coal cavings. The amount of cavings in the bulk sample is an indication of the degree of instability of the borehole walls. Simply watching the cuttings traverse the shaker screens will give a reasonable indication of the amount and size of the cavings in relation to the bulk sample.

Cavings are produced by underbalanced drilling and stress relief. Abrasion of the walls by the drillpipe will also cause cavings, but generally these will not be discer- nible from cuttings because of their small size.

If the pore pressure is higher than the hydrostatic pressure in the borehole, the hydrostatic pressure differential will cause the pore fluids to move toward the borehole. In an impermeable formation, the resultant pressure gradient adjacent to the borehole wall may become great enough to overcome the tensile strength of the rock. When this occurs, the rock fails in tension and cavings are formed.

All parts of the earth’s crust contain stresses that change with depth, area, lithology, history, etc. Drilling a hole in the ground relieves some stresses other than those in the vertical plane, and the hole geometry in relation to some stresses acts to concentrate them. If the borehole wall is not supported sufficiently by the mud column, it may fail either (1) in compression from the vertical stress or (2) in tension from the horizontal stress, or both.

The drilling process causes the formation of microcracks and fractures, and these act as areas of stress concentration and potential initial failure points. Thus it is sometimes noticed that part of a borehole may cave copiously for a short time and then become stable. This is because of the removal of the damaged zone (i.e., cavings) adjacent to the bore/formation interface. Formation is exposed that is more coherent and lacks concentrations of stress, thus it absorbs the extra energy without failing.

Cavings produced by underbalanced drilling are typically long, splintery, concave, and delicate (Fig. 52.14a). Cavings produced by stress relief tend to be more blocky and can vary in size tremendously, depending on the formation characteristics. Examples are shown in Fig. 52.14b.

Remember that if the cavings are clays, they may react with the mud and lose their distinctive morphology. In- terpretations based on reactive clays should be pursued with caution. The quantity and nature of cavings should be regularly reported on the mud log or on a supplementary data log if pressure evaluation services are being performed.

Shale Bulk Density. Shale density determination can be of great value since it provides information on the compaction of the shale. Under normal conditions, shale

‘ACE

FRONT

Q h . L11 PLAN

Fig. 52.14-Cavings resulting from underbalance and stress relief.

density should increase with depth. Any deviation from this consistent trend may indicate that geopressures exist. The magnitude of the bulk density change will vary with the type and magnitude of the geopressure. Often, the bulk density will decrease, but in other cases it may remain constant or continue to increase but at a lower rate than the previously established trend. Several methods are used for measurement of shale bulk density.

Pycnometer Method. By using a container with repeatable volume, this method involves measuring change of weight resulting from displacement of fluid by the sample. The most practical application of this method at the wellsite is to use a mud balance.

Place enough cuttings in the cup so that the balance indicates 8.34 lbm/gal (i.e., density of fresh water) with the cap on. Fill the cup with water and weigh again. The new reading is W2 in the following equation.

8.34 -Ys= 16.68-w2 , . . . . .

where ys is the specific gravity of sample and Wz is the “mud weight” of sample and water, lbmigal.

Mercury Pump Method. The bulk volume of a known weight of sample is measured. The bulk weight of a prepared sample is first established using an accurate chemical balance. The bulk volume of selected cuttings is then determined using a high-pressure mercury pump by the Kobe system (Boyle’s law principle) at a pressure of about 24 psi, which is recorded on the attached pressure gauge. Mercury is used to compress the air around the cuttings but does not contact the sample material.

The high accuracy of the instrument and large amount of sample used (approximately 25 g = 2,000 individual shale cuttings) give good consistency of results. Because of the accuracy and convenience in operation, this method should be used whenever possible; however, very careful and consistent sample handling is necessary for best results.

Buoyancy Method. The sample is weighed in air and in a liquid of known density. This is an alternative version of the pycnometer method. Theoretically, it should be a more accurate method if an accurate laboratory balance


is used. In practice, it is most inaccurate since the density of the liquid will vary with ambient temperature.

Density Comparison Methods. The simplest of these is the “float-and-sink” method. Shale cuttings are immersed in fluid mixtures of different densities in which they will either float or sink, depending on relative densities. This method is inexpensive and quick but is limited in sensitivity because of large difference in the densities of available fluids (approximately 0.1 to 0.05 g/cm3 and easy contamination of calibrated fluids.

Density Gradient Method. This consists of a fluid column in which density varies uniformly with depth. This is prepared by the partial mixing of a light fluid (neothene) and a heavy fluid (tetrabromoethane) in which beads of known density are suspended. A calibration curve of density vs. depth is prepared. Shale cuttings immersed in the column will sink to the level at which their density is the same as the fluid. Depth is recorded and density read off from the calibration curve.

Both of the heavy liquid methods (density comparison and density gradients), while being quick and simple, have the disadvantage of determining the density of individual cuttings. Special care must be taken to ensure that cuttings are true bottomhole cuttings, and several determinations should be made for each interval to avoid anomalous results. Six or eight cuttings should be chosen that are representative and free of dust or cracks that may

trap air and water and result in low apparent densities. In addition, the fluids used have unpleasant odors and some of them may be hazardous to health. Toxicity labels should be checked for specific mixtures but it is a good general rule to use these fluids in a fume hood or with a vapor extraction system.

It is commonly observed that shale density may decrease as much as 0.5 g/cm3 or more. If this reduction occurs over a significant depth interval, the calculated overburden gradient may reverse. The low-density zone also may change in lithologic character. Fissility, plasticity, carbonate content, color change, and other differences may not be apparent. Measurements from cuttings from water-based muds usually are too low, simply because of the adsorption characteristics of clays. Likewise, measurements taken from wireline logs can also give false indications. Specifically, the formation density log can be affected by a rugose hole and the shallow depth of investigation may not read beyond the hydrated zone. The result is erroneously low readings, causing excessive calculated porosities. The sonic log will be affected greatly by hydrated clays, resulting in very high transit times, high porosities, and too low densities.

Values may be successfully obtained from these logs when water-based muds are used, but caution should be exercised as errors may exist, as explained earlier.

SHALE DATA PRESSURE LOG I

Fig. 52.15-Shale data log.

MUD LOGGING 52-21

The best densities are those obtained from wells drilled with less reactive muds, such as oil- or potash-based fluids. Both actual cutting densities and log densities should be accurate because the clay remains in its virgin state.

Increases in density beyond the normal trend because of decreased porosity or calcification should be noted carefully since these may constitute caprocks above geopressures. Precipitation of pyrite or high iron concentration results in abnormally high bulk densities in clays and shales. It has been proposed that in some wells the occurrence of pyrite in shales masked the density reduction caused by porosity increase. Careful microscopic examination of clays may indicate the occurrence of very fine pyrite, and high iron concentration is indicated by a red/brown color cast. Pore pressure interpretations cannot be accomplished by using shale density if heavy minerals are present; however, since shale density is mainly used for qualitative purposes in geopressure evaluation, the role of the other geopressure indicators remains unchanged.

Any decrease in density (without change in clay character) may be recognized as a pressure transition zone.

Recognition of a normal bulk density trend line may be difficult because of degree of scatter in the rectangular coordinate plot. A semilog plot considerably reduces this scatter, but the normal bulk density range (approximately 1.6 to 2.7 g/cm3) results in a more distorted trend line and difficulty in recognizing deviations (Fig. 52.15).

Shale Factor. Ion-exchange reactions take place between an adsorbent solid and a solution. Ions bound to the solid surface are released into the solution and other ions from the solution become fixed at the surface. Ion exchange can proceed by the exchange of positive ions (cations) or negative ions (anions) but not both. The reactivity of a solid compound in ion exchange reactions is governed by its specific surface (surface area per unit volume) and by the surface density of ion exchange sites (points on the surface where ions may be bound). Reac- tivity is expressed as cation or anion exchange capacity (CEC or AEC) using units of milliequivalents (of a suitable ion) per hundred grams (of the compound).

Various clay types have different CEC’s and conse- quently different adsorption capacities. A smectite-rich clay will undergo diagenesis to illite with increasing temperature and ionic exchange. For diagenesis to proceed, water must be flushed from the clays. If potassium exchange cations are not available, a montmorillonite clay will lose its water but will not convert to illite. Thus, if this type of clay is drilled with a water-based mud, the clay will immediately rehydrate and cause severe drilling problems.

Shale factor is a measure of clay CEC. CEC will decrease as clays convert from montmorillonite-rich to illite-rich with temperature (and thus with depth). Pure montmorillonite clays have a CEC of approximately 100 meq/lOO g. Pure illites show no swelling characteristics, but their CEC is generally between 10 and 40 meqilO0 g. Kaolinites have a CEC of approximately 10 meq/lOO g. Of the most common clay types, it is only the smectite group (including montmorillonite) that has an affinity for water. Thus, any clay zone that contains montmorillonite

Fig. 52.16-Shale factor response.

will have an affinity for water in an amount proportional to the montmorillonite content, and this will be shown by a proportional value of shale factor. Note that the shale factor as measured at the wellsite will not give values corresponding to actual chemical CEC. This is because of impurities in the sample, methodology, experimental error, and the fact that the methylene blue dye (used in the titration) is a very large molecule and thus cannot be adsorbed in interlayer sites.

If the clay is calcareous, and calcimetty is also being performed, then the shale factor may be corrected for carbonate content as given by

100 Fstu =

100 - Cca* xFsha, . . . . . . . . . . . . . .

where F $ht = true shale factor, meq/lOO g, F sha = apparent shale factor, meq/lOO g, and

c cart, = carbonate content, %.

For example, a calcareous clay has a carbonate content of 37 % , and an apparent shale factor of 16:

100 Fsht = - 1oo-37(16)=25 meq/lOO g.

Theoretically, shale factor should indicate whether montmorillonite dehydration or compaction disequilibrium was the major mechanism in generating an apparent geopressure. Geopressures caused by compaction disequilibrium indicate that the pressured zone is immature with respect to shallower, normally pressured sediments. This implies that diagenesis has been restricted by the in- efficiency of the dewarering mechanism, resulting in clays containing a larger proportion of montmorillonite within the geopressured zone. Shale factor would thus decrease to the top of the geopressured zone, increase within the zone, and then decrease as the pore pressure gradients decline (Fig. 52.16). Any overall increase in shale factor within a geopressured zone indicates that compaction disequilibrium has played a part in its formation.


EARTH’S SURFACE

- HEATFLOW LINES --- EQUITEMPERATURE LlNES

Fig. 52.17-Distortion of heat flow around an insulating geopressured zone.

If, however, a geopressured zone was caused by montmorillonite dehydration, then upon entering the interval a sharp decrease in montmorillonite content will be observed. Hence the geopressured zone will contain less montmorillonite, because it has been converted to illite, which releases to the pore spaces water that has been unable to escape fast enough and results in a pore pressure increase. Shale factor thus will decrease in the pressured zone (Fig. 52.16).

Shale factor cannot be a geopressure indicator. The differing responses described are not definitive, and geopressure has to be indicated from other sources before an interpretation by use of shale factor can be achieved. Geoprcssures caused by montmorillonite dehydration and compaction disequilibrium may cause no change in shale factor; also, if geopressures were caused by another process (e.g., aquathermal pressuring that results when trapped pore fluids are heated but are unable to expand and is therefore independent of matrix composition), a change may not be reflected in shale factor with depth.

In the past, the consensus was that shale factor should increase in geopressured zones and could thus act as an indicator. Re-evaluation of the various geopressure mechanisms show that this is not necessarily the case. However, shale factor should be capable of delineating between compaction disequilibrium and montmorillonite dehydration as the major geopressure mechanism.

Flowline Temperature. The geothermal gradient, the rate at which subsurface temperature increases with depth, can be calculated from

‘2-11 gG= D -D (loo), . . . . . . . . . . .

2 I

where gG = geothermal gradient, “C/100 m, T, = temperature, “C (at depth D, , m), and T2 = temperature, “C (at depth D2, m).

For any given area, the geothermal gradient is usually assumed constant. While the average gradient across

normally pressured formations may be constant, geopressured formations exhibit abnormally high geothermal gradients. l3

Since a constant flow of heat occurs radially from the earth’s core to the surface, the total flow of heat across any depth increment will be constant. However, the temperature differential across an increment depends on the thermal conductivity of the material. Since overall heat flow from the earth’s surface is generally constant within any particular area, the heat flux through the various formations with depth is in equilibrium. The rate of change of temperature across a formation with a low thermal conductivity (caused mainly by high porosity) will be high; conversely, a low geothermal gradient is indicative of high thermal conductivity formations-i.e., lower porosity. Water and hydrocarbon migration to shallower depths may also affect the geothermal gradient. Pore fluids, as insulators, retain heat so that on migration these hot fluids modify the temperatures of the formations that they pass through and ultimately become trapped. Fowler14 cited examples from the Middle East, Canada, and U.S. oil fields of geothermal gradient bulges that indicated possible entrapment of hot fluids from greater depths. The mechanism also may be related to montmorillonite dehydration, because the huge volume of water squeezed from the clay provides the im- petus for migration. “Dead” basins (i.e., no source rocks) have been shown to exhibit normal geothermal gradients, hence on initial exploration wells the geothermal gradient may indicate the potential of the whole area.

An insulating zone produces a distortion in the isothermal lines that normally run perpendicular to the lines of heat flow (Fig. 52.17; Ref. 15).

Because of the high geothermal gradient, these are more closely spaced in the insulating zone. In the zones above and below, the isothermal lines are more widely spaced in compensation and the zones exhibit a reduced geothermal gradient. The converse occurs in beds of high thermal conductivity (i.e., sands and some limestones)

Since water has a thermal conductivity of about one- third to one-sixth that of most rock matrix materials, it can be seen that thermal conductivity is directly related to the degree of compaction of a formation. The higher- than-normal water content of geopressured shales reduces the thermal conductivity. Therefore, the top of a geopressured zone is marked by a sharp increase in geothermal gradient. The temperature of the mud at the flowline may reflect the geotemperature, and recording of flowline temperature is a practical method to determine temperature gradient, provided variable factors such as pump rate, lag time, ambient temperature, lithology, and temperature changes at the surface that are caused by mud mixing and chemical treatments can be accounted for. In areas where large annual temperature variations occur, considerable differences may be noted in flowline temperatures; even diurnal temperature fluc- tuations may cause a 10°C variation in flowline temperature while drilling.

Prior to reaching a geopressured zone, a temperature transition zone will be encountered in which, because of distortion of the isothermal lines, there will be a reduction in geothermal gradient. In practice, this effect is

52-23 MUD LOGGING

TEMPERATURE DATA LOG I

Fig. 52.18-Flowline temperature log.

reflected in the flowline temperature gradient, even to the extent of a fall in flowline temperature (i.e., a negative gradient), followed by an extremely large increase in flowline temperature as the geopressured zone is penetrated (Fig. 52.18).

A dual temperature probe system with sensors at the flowline and suction pit is effective in removing surface effect, if lagged differential temperature is plotted. It is normally sufficient for the points to be plotted at 30-e intervals unless more frequent temperature variation is noticed, but points plotted at 104 intervals allow more accurate data and better resolution for improved interpretation. Circulations, mud additions, water additions, and other significant events should be noted.

It is found that the resultant temperature curve is broken when the bit is changed, or during short trips or other downtime, and a certain time is necessary for the mud system to re-establish a temperature equilibrium upon circulation. The rate at which this thermal equilibrium is re-established may be significant. as a more rapid re-establishment may indicate an increased geothermal gradient. Drilling variables that affect the

rate of re-establishment of equilibrium include total mud volume. The practice of reducing active pit volume to a minimum, dictated by hole size, aids in reducing the time required to attain equilibrium after tripping and reduces the circulation time needed to stabilize flowline temperature. A discontinuity in the plot also occurs at each casing depth and corresponds to a change in hole size. A higher annular velocity in open hole reduces the amount of heat gained from exposed formations, and a lower annular velocity in the marine riser increases the amount of heat lost to the sea. However, these factors only lead to a change in measured temperature; the rate of change of temperature should remain unchanged. Since pressure predictions can be based on temperature gradient rather than on temperature magnitude, each depth segment between discontinuities can be analyzed separately for gradient trends. It is also helpful to replot a smoothed curve of segments end to end without regard for absolute temperature values. In certain cases it has been found that, instead of plotting the individual segments as an end-to-end smoothed curve, end-to-end plotting of the individual segment trend lines may be of


IIFFERENTIAL PRESSURE RATE OF PENETR*T,ON ,CROSS BOTTOM (PSI) (CONSTANT N.W.0.EC0) 0°C

Fig. 52.19~-Response of drilling rate to geopressure.

value. This trend-to-trend smoothed curve is merely a graphical method of removing irrelevant scatter from the plot.

The reduction in temperature gradient caused by distortion of isothermal lines may be noticed before the geopressured zone is encountered; that is, an advance warning of geopressure may be given. Thus a fall in flowline temperature gradient followed by a sharp rise when the geopressure transition zone is drilled provides a warning that even closer attention must be paid to other drilling parameters to achieve confirmation of possible geopressures. However, like other methods of pressure evaluation, flowline temperature reflects a varying physical parameter in an assumed constant rock type; therefore, changes in lithology must be closely monitored to avoid false indications.

Drilling Models. Bingham I6 proposed that the relationship between ROP, weight on bit (WOB), rotary speed, and bit diameter may be expressed in the general form

R -= ,....................... N

(9)

where R = ROP, ft/min, N = rotary speed, rev/min,

db = bit diameter, ft, W = WOB, lbm,

Kn = matrix strength constant (dimensionless), and

d = formation “drillability” exponent (dimensionless).

Jorden and Shirley ” solved Eq. 9 ford, inserted constants to allow common oilfield units to be used and to produce values of d-exponent in a convenient workable range. Most important, however, they let KD be unity,

removing the need to derive empirical matrix strength constants, but making d-exponent lithology-specific as in

d=

where d = drilling exponent (dimensionless), R = ROP, ft/hr, N = rotary speed, rev/min, W = WOB, lbm, and

db = bit diameter, in.

In a constant lithology, d-exponent will increase as the depth, compaction, and differential pressure across bottom increase. Upon penetration of a geopressured zone, compaction and differential pressure will decrease and be reflected by a decrease in d-exponent (Fig. 52.19).

Differential pressure is dependent on mud density as well as formation pore pressure. Therefore, any change in the mud density used promotes an unwanted change in d-exponent.

Rehm and McClendon” proposed a “mud weight corrected” drilling exponent of the form

dxc =

where d,, = corrected d-exponent (dimensionless),

R = ROP, ftlhr, N = rotary speed, revimin,

dh = bit diameter, in., g+, = normal formation balance gradient, lbm/gal, Pet = effective circulating density, lbm/gal, and

W = WOB, 1,000 lbm,

or in the metric form

. . (12)

with R in m/hr, N in rpm, Win tonnes (1,000 kg), db in cm, and g,p and ,oec in gicm3.

This correction was empirically derived but has been applied worldwide with much success. The use of actual mud density in place of effective circulating density (ECD) has been found to be acceptable within normal limits of accuracy. ECD should, however, be used when available.

Factors not considered by d-exponent in its basic form are drilling hydraulics, tooth efficiency, and matrix strength.

MUD LOGGING 52-25

I

,

J

0°C SEMlLOG SCALE

Fig. 52.20-Example of formation pore pressure gradients for d, plot.

Drilling hydraulics become important in large holes where efficient hole cleaning is impossible and in soft formation where jetting will make a large contribution to drilling.

Matrix strength controls both magnitude and rate of change of d-exponent with depth.

Tooth efficiency can affect d-exponent in two ways: (1) tooth wear will cause a gradual increase in d- exponent (i.e., decrease in ROP), and (2) a change of bit type may produce a change in d-exponent, especially if the change is a radical one (e.g., from milled-tooth bit to an insert or diamond bit).

If differential pressure becomes large, the simple ratio correction to the d-exponent will not eradicate the effect on ROP.

Furthermore, the relationships among force applied, Wldb, rotary speed, N, differential pressure, g,,~,/p~(., and ROP, R, are more complex than the d-exponent formulation would imply. While working well within certain normal working ranges, radical changes in any of these parameters (for example, change in hole size after setting casing) may result in a shift in d-exponent trend.

When plotted on a logarithmic scale against depth, the d-exponent will exhibit an approximately linear increasing trend through “normal,” hydrostatically pressured formations. Where geopressure, abnormally high formation fluid pressure is encountered, d-exponent values will fall consistently below the extrapolation of this normal trend. It has been shown empirically that d-exponent deviation may be related to formation pore pressure anomaly by the simple ratio

Ppa - dxcn ) . . . . . . . . .(13) --- Ppn .xco d

Fig. 52.21-Logging unit systems.

where

PPa = actual pore pressure at depth of interest,

psi, or formation balance gradient, lbmlgal equivalent mud density (EMD),

PPn = normal pore pressure, psi, or formation

balance gradient, lbmlgal (EMD), d xc-0 = observed corrected d-exponent at depth of

interest, and d x-n = expected corrected d-exponent on normal

trend line at depth of interest.

Using this relationship, it is possible to calculate pore pressure or formation balance gradient (equivalent mud density to balance pore pressure) from d-exponent. Alternatively, the relationship may be used to prepare an overlay allowing direct reading of formation balance gradient from the d-exponent plot (Fig. 52.20).

Drilling exponents may be calculated from driller’s data using a simple calculator and manual plotting and trend recognition. However, quality of the data is greatly improved when a data-acquisition system provides WOB, rotary speed, and mud density directly to the logging unit and a minicomputer is used to read these sensors automatically, to perform the calculations, and to print or plot the results. Computer-equipped mud log-


I

it :, :::::t::::i::::l::1:i:Xt

Fig. 52.22-Formation pressure log.

ging units were introduced to provide pressure evaluation services in areas of known geopressured problems (e.g., offshore U.S. gulf coast) and high-risk, hazardous exploration areas (e.g., the North Sea). Fig. 52.21 shows the available equipment configurations of a computerized logging unit. In addition to pore pressure, this type of unit commonly provides a pressure log including supplementary calculations of fracture pressure, overburden pressure, and kick tolerance (Fig. 52.22).

Petrophysical Measurements Mud Log Data. As discussed previously, mud log data are qualitative in nature. It is not possible with conventional mud log measurements to obtain quantitative values of such parameters as porosity, permeability, hydrocarbon saturations, etc. However, the mud logging unit may provide special equipment or services, allowing more quantitative evaluations.

For example, while a mud log gas analysis cannot be truly representative of gas production composition, gas analysis of recovered fluids from a well test can be. Us- ing conventional gas analyzers and chromatograph, a quantitative analysis of recovered natural gas may be obtained. For more complex fluids, special chromato- graphs, pyrolyzers, or analyzers can give complete analysis of oils or sour gas. The logging unit also may provide ionic analysis of recovered waters and, by use of tritium ( 3H) or nitrate (NO3) tracers, provide discrimination between recovery of mud filtrate and true formation water. These types of service can be of special

value in remote locations where logistics or distance prevent rapid transport of samples to an analytical laboratory.

Core Analysis. In addition to gas and fluid analysis, conventional core analyses I9 (porosity, bulk density, permeability, and saturations) also may be performed in the logging unit when the drilling operation is remote from the laboratory. Wellsite core analysis offers the advantages of rapid evaluation and high-quality samples from fresh core but is rarely of the high quality to be expected from the specialized equipment and personnel in a core laboratory. A new technique, which is suitable to the logging unit, uses a pulsed nuclear magnetic resonance analyzer to determine fluid content, total and free-fluid porosity, and permeability. This device, working on a principle analogous to the nuclear magnetic logging tool (NML), provides accurate, repeatable data from minimal quantities of sample and without complex sample preparation. Samples may be obtained without causing core or sidewall core destruction and the test may be performed on cuttings.

Drilling Porosity

The d-exponent (Fig. 52.20) develops a consistent trend with depth controlled by increasing overburden loading and compaction. Changes in formation pore pressure gradient will result in major, consistent deviations from this trend. The d-exponent data also will exhibit minor,

MUD LOGGING 52-27

POROSITY PERMEABILITY

I

ROCK PROPERTIE

[MILLIDARCIES]

FORMATION DENSITY

PSEUD( 1~ ~~ )-SON1

Fig. 52.23-Drilling porosity log.

inconsistent scatter about the prevailing trend, reflecting continuous variation in rock mineralogy, cohesion, and porosity.

More sophisticated, second-generation drilling exponents are able to isolate the major pore pressure and minor rock character variations. With this type of analysis it is possible to provide a continuous log of pore pressure and “drilling porosity.” It is important to remember that drilling porosity, although scaled in percentage units, is not a true porosity measurement. It is primarily a rock strength indicator, reflecting both porosity and intergrain cohesion. As such, its response is very similar to that of the sonic log, and the two logs cor- relate extremely well (Fig. 52.23).

Unlike the d-exponent, the second generation drilling exponents require complex manipulations and iterations, limiting their use to logging units equipped with a computer. Also, unlike the d-exponent, they do not involve a widely published and used single method. Although based on similar drilling response models, all mud logging contractors offer drilling porosity logs involving their own unique mathematical methods that are commonly held as proprietary secrets. While understandable from a commercial view, this policy places the user in the position of being able to judge the value and reliability of a particular log only on the bases of his or her own experience and limited published results. It is hoped that, with the maturation of this type of service, wider publication and discussion of methods will begin.

Drilling Engineering Services The mud logging unit can provide two levels of service of value to the drilling engineer-data acquisition and data analysis.

Data Acquisition

An automatic data acquisition system located in the logging unit will monitor sensors installed on equipment, flowline, mud pits, pumps, etc. Simple calculations are performed on the data (e.g., calculation of total depth and ROP, summation of pit volumes, comparison of current values with high- and low-alarm setpoints). Results then are displayed on TV monitors at various locations around the rig and may be recorded on a printer or magnetic tape. By use of a dedicated land line or satellite link, data can be transmitted to a remote location, allowing several rigs to be monitored from a single central control room.

This type of equipment was introduced by mud logging service companies as a means of obtaining drilling and mud data more reliably and rapidly than could be expected from standard rig instrumentation. While these data were required initially for pressure evaluation analyses, the data acquisition system provided an important secondary function as a rig monitoring service by supplying the drilling engineer accurate, up-to-date drilling information while away from the rig floor and a complete foot-by-foot record of drilling progress and performance on paper or magnetic tape.


Since that time. several conventional rig instrumentation manufacturers have upgraded their product lines to include similar data acquisition systems that operate in an unmanned, or “stand-alone,” mode. While this offers the operator the advantage of flexibility in selecting services (i.e., the mud logging service best suited to the geologist and the data acquisition service best suited to the engineer), it does have drawbacks.

Reliability of a data acquisition system is primarily controlled by the operation of its sensors. In the rigorous environment of the rig this requires regular attention. The success of a stand-alone data acquisition system is related entirely to the training and motivation of the rig crew or the availability of manufacturer’s service personnel.

The mud logging unit is manned at all times. Trained personnel are available at all times to calibrate, maintain, and service the data acquisition system and its sensors. Since these personnel are already at the wellsite as part of the mud logging service, this extra margin of reliability is achieved without extra cost beyond the similar cost of the data acquisition hardware.

Data Analysis Beyond simple data acquisition, the mud logging service also may supply computers, software, and specialized wellsite personnel for drilling data analysis. The desirability of such services depends on the difficulty and cost of the drilling operation, availability of oil company expertise at the wellsite, and quality of communication with the exploration headquarters.

For example, infill drilling in an established domestic field using a well-developed drilling program, experienced wellsite supervisors, and close communication with home office requires data acquisition only as a means of monitoring optimal and safe adherence to the drilling program. On the other hand, on an offshore wildcat, the availability of data analysis and expertise at the wellsite can be very cost effective. *O An increase in drilling efficiency or a decrease in downtime sufficient to save a single day of rig time can, in these circumstances, produce sufficient savings to pay for data analysis services for the whole well.

Data analysis services offered include: (1) bit optimization-selection of bit type and operating parameters to optimize bit ROP and bit life; (2) bit economics-cost per unit depth and breakeven calculation between bit types; (3) drilling hydraulics2’ -optimization of drillstring, nozzle, and annulus hydraulics; (4) directional analysis-determination of well path, bottomhole position, and intersection points for deviated wells; (5) trip monitoring-calculation of string weights, swab pressures and fillup requirements for tripping, monitoring of pit level deviations, and overpull (fric- tional drag in the borehole); (6) casing calculations-assembly of casing tally, calculation of cement volumes and mixing requirements, and monitoring of displacement; (7) pressure control-calculation of mud weight, volume and pressure requirements for safe well control lo; and (8) logistics-usage and inventory control of well expandables, equipment maintenance schedul- ing, well progress data base, and report generation.

Selecting a Mud Logging Service Mud logging contractors commonly offer three levels of standard service: (1) standard mud logging; (2) mud logging and data acquisition, and (3) mud logging and data analysis (including pressure evaluation). For the most basic level of mud logging, a single operator may tje responsible for 24-hour operation. More sophisticated services and data acquisition usually require two geologists working 12-hour tours. Data analysis services require two people, a geologist and an engineer. on each tour.

Each of these services may be augmented with extra equipment such as sensors, special gas detectors, pyroanalyzers, more powerful computers or peripherals and specialist personnel at extra day rate as the drilling program demands. 2,10

At least two mud logging contractors now offer an additional, fourth level of service in which mud logging and data analysis are combined with an MWD service.

Very little of the information gathered by a mud logging unit is not obtainable from some other source. For example, stand-alone instrumentation can monitor gas, mud, and drilling parameters; rig crews can catch samples; porosity is available from wireline logs; and oil company geologists and engineers may perform geological evaluation and drilling data analysis. Why then is mud logging such a widely used service?

The advantage of mud logging service is that all these data may be derived from a single source, the mud logging unit, located at the wellsite and continuously manned with dedicated, specially trained personnel. Therefore the data are obtained more reliably, more quickly, and usually more economically than from any other combination of sources.

Reliability and speed therefore are the tests required in selecting a mud logging contractor. The equipment must be designed and maintained adequately to provide reliable and safe operation in the rigorous wellsite environment. The wellsite crew must be trained to operate, maintain, and troubleshoot the equipment and to under- stand its output. The contractor must maintain adequate service personnel and inventory to allow rapid repair or changeout in the event of major malfunctions. The logging crew must be trained in geological and engineering theory, be experienced in practical drilling operations, and have a thorough knowledge of the geological section, drilling program, and operational procedures of the particular well and operator.

Once a contractor is selected, economy becomes the prime consideration in choosing a level of service. In day-rate drilling, time and money may be directly equated. Any service that speeds well progress, reduces downtime, or promotes decision-making is potentially a cost saver. Even on footage drilling, personnel, com- munications, etc., are cost-generating factors which may be reduced by improved drilling efficiency. On rank wildcat exploration wells, the “bird in the hand” philosophy may be desirable to obtain data at the earliest possible time as a hedge against the risk of it being unavailable later. For example, to obtain porosity measurements from the mud logging unit while drilling is an investment against later borehole loss or damage that may prevent later wireline logging.

MUD LOGGING 52-29

Quantification of cost saving is possible by using the same methods used to calculate drilling cost per foot. In its simplest form this is

Cd= Cbe + Crr/

) . . . . . . D, (14)

where Cd = drilling cost, $/m, C, = rig cost, $/D,

Cbp = cost of bits and expendables, $, 11 = time on location, days, D, = total well depth, m.

For optimization of services and products this can be ex- panded to the form

Cd=[(CFI +CF2 +. ~CFn)+(Cdrl +CdR.. .cdrn)

X(t,+tt+t,+t,+td)];D, . . . . . . . . .(15)

and

CdxD,=C(CF),, +C(C,,), xc(t),, . . I..... (16)

where CF = individual fixed cost items or footage

charges services, $, Cdr = individual day rate services, rentals,

salaries, etc., $, t, = rotating time, days, t, = tripping time, days, to = off-bottom time (reaming, conditioning,

well control, etc.), days, t, = evaluation time (logging, testing, coring,

etc.), days, and td = downtime (breakdowns, weather, decision

making, etc.), days.

Using this formulation, it is possible to calculate the decrease in one cost category required to offset an increase in any other.

For example, consider the use of drilling optimization. Let us assume, conservatively, that regional statistics indicate that by upgrading a mud logging unit to include data acquisition equipment no overall ROP improvement is obtained but that a well can be completed using one less bit. Well cost as a result of this is given by

(cd xD,)‘=[C(c~)n -AcFbll

+WC,,), +Ac,,l[W,), --Art, I, . (17)

where ACFbl = cost of one bit saved, dollars,

AC,, = extra cost of mud logging, dollars/D, (f,),? = total time on location, days At,, = time for one trip saved, day, and

(Cd xD,)’ = well cost. dollars,

For cost effectiveness (i.e., for the additional service to save its own cost or more), overall well cost must be unchanged or reduced. Thus,

A(cd XD,)=(cd XD,)‘-(cd XD,)Io, . (18)

A(CdXD,)= -Acml -[E(c,,), xAt,,l

+AC,, x[C(t,), -At,,], . . . . (19)

AC,, I AC,, + [~(c,,>, +Af,, 1

’ . ’ ’ ’ ’ [E(t,), -At,,] (20)

If this is evaluated as true, that the day rate for the extra equipment is in fact less than the evaluated expres- sion, then the service is cost effective on the particular well. In this case, substituting some reasonable figures such as:

Onshore Offshore

ACFbl = $l,ooo ACF~I = $1,000 z(cdr) n = $6,000/D E(c&)n = $19,OlWD

Ar,l = 12 hours=0.5 day Atrj = 12 houn=O.S day C(AZ[)~ = 30 days E(Afl), = 35 days

we obtain for onshore:

AC,, I 1,000+(6,000)(0.5)

(30 -0.5)

=$135.59/D.

The extra equipment will result in an overall cost saving on the well so long as it does not increase the mud logging daily rate by more than $135/D.

We obtain for offshore:

1,000+(19,000)(0.5) AC,, 5

(35 -0.5) =$304.35/D.

Using these same figures, let us now assume that, in addition to saving one bit, an overall decrease of 5% in drilling time is also achieved. If I, =21 days, saving in rotating time=21 ~5% = 1.05 days, then for onshore:

Ac XT

I 1,000+[6,000 (0.5+1.05)]

(30-0.5-1.05) =$362.04/D.

For offshore:

AC,, = 1,000+[19,000 (0.5+1.05)]

(35-0.5-1.05) =$910.31/D.


These cost justifications, or cost savings, refer only to the extra cost of data acquisition above that of standard mud logging and include only those benefits resulting from drilling optimization. Other cost savings resulting from better rig and mud monitoring and well control may also be quantifiable from a study of regional drilling statistics.

A cost benefit analysis of this type is a worthwhile approach to all aspects of drilling cost reduction. Cost saving resulting from advanced evaluation and monitoring commonly is appreciated in expensive offshore exploration. As the above examples show, such techniques may be equally successful in comparatively cheaper onshore development drilling, especially where problems such as geopressure or crooked holes occur.

Standards For and Status of Services The terms “mud logging” covers a diverse range of services and qualities of service. It is regrettable that, in the U.S. especially, the whole industry is accorded a status reflecting its lowest level. Field employees of the higher quality and more reputable contractors commonly eschew the term “mud logger,” preferring the title “logging geologist” or “logging engineer,” depending on their educational background. The wide range of equipment and techniques used by such companies commonly results in their personnel being the best educated and trained service personnel present on any wellsite.

In 1980, the Sot. of Professional Well Log Analysts (SPWLA) established a Hydrocarbon Well Log Stan- dards Committee comprising members of both the service company and exploration company sides of the field. The efforts of the committee have done much toward establishing standards and status representative of the best of the industy. 22,23 I express my gratitude to this committee and its members for these efforts and for assistance in the development of this chapter.

Nomenclature Cbr

= cost of bits and expendables, dollars C carh = carbonate content, %

Cd = drilling cost, dollars/m C dr = individual day rate services, rentals,

salaries, etc., dollars Cf = individual fixed cost items or footage

charges services, dollars C, = rig cost, dollars/D

d = formation “drillability” exponent (dimensionless)

db = bit diameter, ft or in. d, = “normal” bit diameter (m) d 0~ = observed bit diameter (m) d,,. = corrected d-exponent (dimensionless) d,,.,, = expected corrected d-exponent on nor-

mal trend line at depth of interest d,,, = observed corrected d-exponent at depth

of interest Fh = apparent shale factor, meq/lOO g F h = true shale factor, meq/lOO g G P” = normalized total gas (%)

G poB = observed total gas (R)

gc = geothermal gradient, “C/100 m gq% = normal formation balance gradient,

lbm/gal KD = matrix strength constant (dimensionless) N= rotary-speed, rev/min

Ppu = actual pore pressure at depth of interest, psi, or formation balance gradient, lbm/gal equivalent mud density @MD)

P/m = normal pore pressure, psi, or formation

4n = qoB = q/J = R=

R, = R OS =

td =

balance gradient, lbm/gal (EMD) “normal” mud flow rate (m3/s) observed mud flow rate (m3/s) pump output, m3/s) ROP, ft/min “normal” ROP (m/s) observed ROP (m/s) downtime (breakdowns, weather, deci-

t, =

sion making, etc.), days evaluation time (logging, testing, corm

fl =

Ol), =

I, =

ing, etc.), days

lag time, seconds total time on location, days

off-bottom time (reaming, conditioning,

t, =

t, =

v =

;; =

VP =

varl =

w=

(CdXD,)’ =

AC Fbl =

AC,, = At,, = Per =

well control, etc.), days rotating time, days tripping time, days annular volume, m 3 /m hole capacity, m3/m pipe capacity and displacement, m3/m annular velocity, m/s WOB, Ibm well cost, dollars cost of one bit saved, dollars extra cost of mud logging, dollars/D time for one trip saved, day

effective circulating density, Ibm/gal

References 1. “Field Geologists Training Guide.” Exploration Logging Inc.,

Sacramento, CA (Jan. 1979). 2. “Mud Logging: Principles and Interpretation,” Exploration Log-

ging Inc., Sacramento, CA (Aug. 1979). 3. “Formation Evaluation-Part I: Geological Procedures.” Ex-

ploration Logging Inc., Sacramento, CA (Feb. 1981). 4. Hopkins, EA.: -“ Factors Affecting Cuttings Removal During

Rotary Drilling,” .I. Pet. Tech. (June 1967) 807-14; Trans.. AIME, 240.

5. Sifferman, T.R. et al.: “Drill Cuttmg Transport m Full Scale Ver- tical Annuli,” J. Pet. Tech. (Nov. 1974) 1295-1302.

6. Low, J.W.: “Examination of Well Cuttings,” Quarterly cjj r/w Colorado School ofMines (1951) 46, No. 4. l-48.

7. Maher, J.C.: Guide book V/I/: Lqging Drill Curtings, Oklahoma Geological Survey, Norman (1959).

8. McNeil, R.P.: “Lithologic Analysis of Sedimentary Rocks.” Eu[(., AAPG (April 1959) 43, No. 4, 854-79.

9. Clementr, D.M., Demaison, G.J., and Daly, A.R.: “Wellsite Geochemistry by Programmed Pyrolysis.” paper OTC 3410 presented at the 1979 Offshore Technology &if&-ence. Houston, April 30-May 3.

10. “Theory and Evaluation of Formation Pressures: The Pressure Log Reference Manual.” Exploration Logging Inc., Sacramento, CA (Sept. 1981).

I I. Hottman, C.E. and Johnson, R.K.: “Estimation of Formation Pressures from Log-Derived Shale Properties,” .I. Per. Tech. (June 1965) 717-22: Trans.. AIME. 234.

MUD LOGGING 52-31

12. Goldsmith. R.G.: “Why Gas-Cut Mud is Not Always a Serums Problem,” Work! Oil (Oct. 1972) 175, No. 5, 51-54, 101.

13. Dawdle, W.L. and Cobb, W.M.: “Statrc Formation Temperature From Well Logs,” J. Per. Tech. (Nov. 1975) 1326-30.

14. Fowler. P.T.: “Telling Live Basms from Dead Ones by Temperature,” World Oil (May 1980) 190, No. 6, 107-22.

15. Lewis, C.R. and Rose, S.C.: “A Theory Relating High Temnerature and Ovemressures.” J. Pet. Tech. (Jan. 1970) ll-lb.

16. Bineham. M.G.: A New Amroach to lnfemretinn Rock Dnllabiii- ry, Fetroieum Publishing i3b., Tulsa (1965). ”

17. J&en, J.R. and Shirley, O.J.: “Applicatmn of Drillmg Perfor- mance Data to Overpressure Detection,” J. Per. Tech. (Nov. 1966) 1387-94.

18. Rehm. B. and McClendon, R.: “Measurement of Formation Pressure From Drilling Data,” Dn’llin~, Reprint Series, SPE. Dallas (1973) 6a, 49-60.

19. Anderson, G.: Corin,q und Core AnaI~~sis Hundbook. Petroleum Publishing Co., Tulsa (1975).

20. Bellottt, P. and Giacca, D.: “Pressure Evaluation Improves Drill- ing Programs,” Oil and Gus J. (Sept. 11, 1978) 76-85.

21. “Drilling Hydraulics Manual,” Exploration Loggmg Inc., Sacramento, CA (July 1983) 8. l-8; 9, l-10; 10, 1-7: D, l-4.

22. “SPWLA Standard No. 1: Standard Hydrocarbon Well Log Form.” SPWLA. Houston (June 1981).

23. “SPWLA Standard No. 2: Hydrocarbon Well Log Calibration Standards,” SPWLA, Houston (June 1981).

General Reference Jorden, J.R. and Campbell, F.L.: Well Log,& I-Rock Prupenies,

Borehole Environmenf, Mud and Temperarure Logging. Monograph Series, SPE, Dallas (1984) 9.

Documents

52 Mud Logging